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ALABAMA POWER CO - Annual Report: 2005 (Form 10-K)

THE SOUTHERN COMPANY
Table of Contents

 
 
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, 2005
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)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (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 Florida 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)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (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   5.70% Series X
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, 2005.
 
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)8    
___________________________________
 
Preference stock, non-cumulative, $100 par value   Gulf Power Company
6.000% 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, 2005.
 
8   This series was redeemed in January 2006.

 


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     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
         
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
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of
the Act. Yes ___No þ (Response applicable to all registrants.)
     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. þ
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
             
    Large        
    Accelerated   Accelerated   Non-accelerated
Registrant   Filer   Filer   Filer
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
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ (Response applicable to all registrants.)

 


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     Aggregate market value of The Southern Company’s common stock held by non-affiliates of The Southern Company at June 30, 2005: $25.9 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, 2006  
The Southern Company
  Par Value $5 Per Share     741,738,001  
Alabama Power Company
  Par Value $40 Per Share     9,250,000  
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 2006 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Information Statements of Alabama Power Company and Mississippi Power Company relating to each of their respective 2006 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.
 

 


 

Table of Contents
         
        Page
 
  PART I    
 
       
  Business   I-1
 
  The SOUTHERN System   I-2
 
  Construction Programs   I-4
 
  Financing Programs   I-5
 
  Fuel Supply   I-5
 
  Territory Served by the Utilities   I-6
 
  Competition   I-9
 
  Regulation   I-10
 
  Rate Matters   I-12
 
  Employee Relations   I-14
  Risk Factors   I-16
  Unresolved Staff Comments   I-25
  Properties   I-26
  Legal Proceedings   I-29
  Submission of Matters to a Vote of Security Holders   I-30
 
  Executive Officers of Southern Company   I-31
 
  Executive Officers of Alabama Power   I-33
 
  Executive Officers of Mississippi Power   I-34
 
       
 
  PART II    
 
       
  Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   II-1
  Selected Financial Data   II-2
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   II-2
  Quantitative and Qualitative Disclosures about Market Risk   II-3
  Financial Statements and Supplementary Data   II-4
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   II-5
  Controls and Procedures   II-6
  Other Information   II-6
 
       
 
  PART III    
 
       
  Directors and Executive Officers of the Registrants   III-1
  Executive Compensation   III-8
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   III-18
  Certain Relationships and Related Transactions   III-20
  Principal Accountant Fees and Services   III-22
 
       
 
  PART IV    
 
       
  Exhibits and Financial Statement Schedules   IV-1
 
  Signatures   IV-2
 i

 


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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 of 1992
  Energy Policy Act of 1992
Energy Act of 2005
  Energy Policy Act of 2005
Energy Solutions
  Southern Company Energy Solutions, Inc.
EPA
  United States Environmental Protection Agency
FERC
  Federal Energy Regulatory Commission
FMPA
  Florida Municipal Power Agency
FP&L
  Florida Power & Light Company
Gas South
  Gas South, LLC, an affiliate of Cobb Electric Membership Corporation
Georgia Power
  Georgia Power Company
Gulf Power
  Gulf Power Company
Hampton
  City of Hampton, Georgia
Holding Company Act
  Public Utility Holding Company Act of 1935, as amended
IBEW
  International Brotherhood of Electrical Workers
IIC
  Intercompany Interchange Contract
IPP
  Independent power producer
IRP
  Integrated Resource Plan
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 Corporation, 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
 ii

 


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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.
TVA
  Tennessee Valley Authority
 iii

 


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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 and repairs, environmental regulations and expenditures, earnings growth, dividend payout ratios, projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and Georgia Power, impacts of the adoption of new accounting rules, 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, implementation of the Energy Act of 2005, 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, FERC matters, IRS audits and Mirant 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, including rate cases relating to fuel cost recovery;
  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.
The registrants expressly disclaim any obligation to update any forward-looking statements.
 iv

 


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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 and Mississippi. 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 Florida corporation that has had a continuous existence since it was originally organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under the laws of the State of Florida on November 2, 2005.
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. On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement, under which Savannah Electric will merge with and into Georgia Power, with Georgia Power as the surviving corporation in the merger. Following the merger, Southern Company will continue to own all of the outstanding common stock of Georgia Power. The merger must be approved by the shareholders of Savannah Electric and the sole shareholder of Georgia Power, and is subject to receipt of related regulatory approvals of the FERC, Georgia PSC and Federal Communications Commission. Assuming the timely receipt of all required approvals, Georgia Power and Savannah Electric expect to complete the merger by July 2006. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Retail Regulatory Matters — Merger” in Item 8 herein for additional information.
     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 was 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 or membership interests 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, was a competitive retail natural gas marketer which served communities in Georgia until January 4, 2006 when it sold substantially all of its assets to Gas South (see “The SOUTHERN System – Other

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Business” herein for additional information). 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.
     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 “Territory Served by the Utilities” 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 Progress Energy Carolinas, 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.
     The IIC 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. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters — Intercompany Interchange Contract” of each of the registrants in Item 7 herein, Note 3 to the financial statements of Southern Company and each of the retail operating companies and Note 2 to the financial statements of Southern Power, all under “FERC Matters — Intercompany Interchange

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Contract” in Item 8 herein for information on the FERC proceeding related to the IIC.
     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 “Regulation — Atomic Energy Act of 1954” herein for additional information.
Southern Power
Southern Power is an electric wholesale generation subsidiary with market-based rate authority from the FERC. 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 state PSCs). Southern Power’s business activities are not subject to traditional state regulation of utilities but are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation and electric transmission 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, 2005, Southern Power had 5,403 megawatts of generating capacity in commercial operation.
Other Business
On January 4, 2006, Southern Company Gas completed the sale of substantially all of its assets, including natural gas inventory, accounts receivable and customer list to Gas South. See Note 3 to the financial statements of Southern Company under “Southern Company Gas Sale” in Item 8 herein for additional information.
     Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses.
     SouthernLINC Wireless serves Southern Company’s retail operating companies and marketing its services to non-affiliates within the Southeast. SouthernLINC Wireless bundles multiple communication options into one phone including InstantLINCSM Mobile to Mobile, cellular service, text messaging, wireless internet access and wireless data. Its system covers approximately 128,000 square miles in the Southeast.
     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.

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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. For estimated construction and environmental expenditures for the periods 2006 through 2008, see Note 7 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric and Note 6 to the financial statements of Southern Power all under “Construction Program” in Item 8 herein.
     Estimated construction costs in 2006 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
  $ 127     $     $     $     $     $     $ 127  
Other generating facilities, including associated plant substations
    1,110       458       533       72       23       9       15  
New business
    356       143       156       26       20       11        
Transmission
    450       104       296       15       24       11        
Joint line and substation
    5                   5                    
Distribution
    284       127       97       15       33       12        
Nuclear fuel
    153       58       95                          
General plant
    288       61       74       30       26       2       20  
     
 
  $ 2,773     $ 951     $ 1,251     $ 163     $ 126     $ 45     $ 162  
     
 
*   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 “Other Business” 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 changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
     Under Georgia law, Georgia Power and Savannah Electric each are required to file an IRP 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 “Rate Matters — Integrated Resource Planning” herein for additional information.
     See “Regulation — Environmental Statutes and Regulations” 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.

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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.
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 2003 through 2005 are shown below:
                                         
    Coal   Nuclear   Hydro   Gas   Oil
    %   %   %   %   %
     
Alabama Power
                                       
2003
    64       19       8       9       *  
2004
    65       19       6       10       *  
2005
    67       19       6       8       *  
Georgia Power
                                       
2003
    75       22       3       *       *  
2004
    76       22       2       *       *  
2005
    75       19       2       3       1  
Gulf Power
                                       
2003
    87       **       **       13       *  
2004
    84       **       **       16       *  
2005
    86       **       **       14       *  
Mississippi Power
                                       
2003
    74       **       **       26       *  
2004
    69       **       **       31       *  
2005
    70       **       **       30       *  
Savannah Electric
                                       
2003
    94       **       **       4       2  
2004
    96       **       **       3       1  
2005
    79       **       **       20       1  
SEGCO
                                       
2003
    100       **       **       *       *  
2004
    100       **       **       *       *  
2005
    100       **       **       *       *  
Southern Power
                                       
2003
    **       **       **       99       1  
2004
    **       **       **       100       *  
2005
    **       **       **       100       *  
Southern Company system — weighted average
                                       
2003
    71       16       4       9       *  
2004
    69       16       3       12       *  
2005
    71       15       3       11       *  
 
*   Less than 0.5%.
 
**   Not applicable.
     For the retail operating companies and SEGCO, the average costs of fuel in cents per net kilowatt-hour generated for 2003 through 2005 are shown below:
                         
    2003   2004   2005
     
Alabama Power
    1.54       1.69       2.02  
 
                       
Georgia Power
    1.46       1.55       2.04  
 
                       
Gulf Power
    2.11       2.32       2.77  
 
                       
Mississippi Power
    1.96       2.50       3.11  
 
                       
Savannah Electric
    2.40       2.62       4.15  
 
                       
SEGCO
    1.54       1.60       1.69  
 
                       
Southern Company system — weighted average
    1.67       1.89       2.39  
     The retail operating companies have long-term agreements in place from which they expect to receive approximately 84% of their coal burn requirements in 2006. These agreements cover remaining terms up to 8 years. In 2005, the weighted average sulfur content of all coal burned by the retail operating companies was 0.8% 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 2005, Southern Company purchased approximately $121 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 Matters — 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 Southern Company system has long-term agreements in place for its natural gas burn requirements.

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For 2006, the Southern Company system has contracted for 130 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 13 years. In addition to gas supply, the Southern Company system has 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 “Rate Matters — Rate Structure” 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 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 was completed in 2005 and is expected to provide adequate spent fuel storage through 2015 for both units. The facility can 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 is operational and can be expanded to accommodate spent fuel through the life of the plant.
     The Energy 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, including Alabama Power and Georgia Power. This assessment is being paid over a 15-year period ending in 2006. 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 “Nuclear Fuel Disposal 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, and at wholesale currently to OPC, MEAG, Dalton and Hampton. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Merger” in Item 8 herein for information on the planned merger of Savannah Electric with and into Georgia Power.

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     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. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Merger” in Item 8 herein for information on the planned merger of Savannah Electric with and into Georgia Power.
     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 organizations, 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.
     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 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. Three of these organizations obtain their power from TVA, one from Southern Power under a 15-year agreement which began in January 2005 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

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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 entered into a new control area compact agreement effective March 1, 2005 which replaced previous coordination service agreements.
     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 begin purchasing such capacity for a 10-year term. In January 2005, 29 electric cooperative organizations served by OPC and one served by Southern Power began purchasing a total of 700 megawatts of capacity from Georgia Power under individual contracts for 10-year terms. Also, in January 2005, the electric cooperative served by Southern Power began purchasing 25 megawatts of peaking capacity from Georgia Power under a 10-year contract. This electric cooperative will purchase 50 megawatts of coal-fired capacity from Georgia Power beginning April 1, 2006 and ending December 31, 2014 and another 75 megawatts of coal-fired capacity from Georgia Power beginning June 1, 2010 and ending December 31, 2019. 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. This contract expired on December 31, 2005. See Note 6 to the financial statements of Alabama Power under “First Mortgage Bonds” in Item 8 herein for further information on this contract.
     In December 2001, Alabama Power entered into a power sales agreement with AMEA which began on January 1, 2006. Under this contract, AMEA supplies 70 to 95 megawatts of power from its combustion turbine plant and Alabama Power serves the remainder of its member needs through 2010. Beginning in 2011, the amount of power supplied to AMEA by Alabama Power is fixed at 2010 levels and AMEA has the option to seek other suppliers for its incremental growth needs through 2015, at which time the contract terminates.
     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 with Georgia Power and Southern Power pursuant to which it will purchase 134 megawatts from Georgia Power and the balance of its requirements, net of self-owned generation, from Southern Power for a 15-year term. In addition, Georgia Power serves the full requirements of Hampton’s electric distribution system under a market-based contract. 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 — “Power Sales Agreements” of Southern Power in Item 7 herein for information concerning its PPAs.

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     SCS, acting on behalf of the retail operating companies, also has a contract with SEPA providing for the use of those companies’ facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain United States government hydroelectric projects.
     The retail service rights of all electric suppliers in the State of Georgia are regulated by the 1973 State Territorial Electric Service Act. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein (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 this 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, this 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 “Competition” 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 “Competition” herein for additional information. In connection with the proposed merger with Savannah Electric, Georgia Power has filed an application with the Georgia PSC for approval of the transfer of Savannah Electric’s service territory to Georgia Power at the effective time of merger.
     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 of 1992. The Energy Act of 1992 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 2005, Alabama Power purchased approximately 137 million kilowatt-hours from such companies at a cost of $5.7 million.
     Georgia Power currently has contracts in effect with 10 small power producers whereby Georgia Power purchases their excess generation. During 2005, Georgia Power purchased 22 million kilowatt-hours from such companies at a cost of $0.9 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2005, Georgia Power purchased 238 million kilowatt-hours at a cost of $68 million from these facilities.
     Gulf Power currently has agreements in effect with various industrial, commercial and qualifying facilities pursuant to which Gulf Power

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purchases “as available” energy from customer-owned generation. During 2005, Gulf Power purchased 17 million kilowatt-hours from such companies for approximately $0.9 million.
     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 2005, Mississippi Power purchased approximately 39 million kilowatt-hours of excess generation at a cost of approximately $1 million.
     During 2005, Savannah Electric purchased energy from seven customer-owned generating facilities. Six of the seven customers provide only energy to Savannah Electric. These six customers make no capacity commitment and are not dispatched by Savannah Electric. Savannah Electric does have a contract with the remaining customer for eight megawatts of dispatchable capacity and energy. During 2005, Savannah Electric purchased a total of 62.3 million kilowatt-hours from the seven suppliers at a cost of approximately $3.3 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.
     Generally, 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 “Territory Served by the Utilities” 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 the Mississippi PSC, in part, retail service territories. See “Territory Served by the Utilities” and “Rate Matters” herein for additional information.
Federal Power Act
In July 2005, the U.S. Congress passed the Energy Act of 2005 which repealed the Holding Company Act effective February 8, 2006. The retail operating companies, Southern Power and its generation subsidiaries and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and therefore remain subject to the rate, financial and accounting jurisdiction of the FERC under the Federal Power Act. Certain financing approvals which would have been obtained from the SEC under the repealed Holding Company Act now must be obtained from the FERC. In implementing repeal of the Holding Company Act, the FERC sought to minimize unnecessary administrative burdens and decided to retain an “at cost standard” for services rendered by system service companies such as SCS, to permit certain existing financing authorizations to remain effective without further action by the FERC and to reduce reporting requirements. In addition to its repeal of the Holding Company Act, the Energy Act of 2005 authorized the FERC to establish regional reliability organizations authorized to enforce reliability standards, established a process for the FERC to address impediments to the construction of transmission and established clear responsibility for the FERC to prohibit manipulative energy trading 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

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generating stations having an aggregate installed capacity of 1,074,696 kilowatts.
     In December 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 completing field studies for the facility. The license for the Morgan Falls project expires in 2009. In July 2005, Alabama Power filed two applications with the FERC for a new 50-year license for its seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan and Bouldin) and a new 50-year license for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine developments expire in 2007. In 2006, Alabama Power will initiate the process of developing a relicensing application for the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license will have to be submitted to the FERC in 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters — Hydro Relicensing” of Alabama Power in Item 7 herein for additional information.
     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. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.
     Licenses for all projects, excluding those discussed above, expire in the period 2013-2033 in the case of Alabama Power’s projects and in the period 2014-2039 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.
     The NRC operating licenses for Plant Vogtle units 1 and 2 currently expire in January 2027 and February 2029, 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 the unit 1 and 2 until 2034 and 2038, respectively. Similarly, in May 2005 the NRC granted Alabama Power a 20-year extension of the licenses for both units at Plant Farley which permits operation of units 1 and 2 until 2037 and 2041, respectively.
     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 MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters” of each of the registrants 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.

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     Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each retail operating company and SEGCO. 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 by the EPA 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 Matters — Environmental Statutes and Regulation — Environmental Remediation” of Southern Company and each of the retail operating companies in Item 7 herein for information regarding environmental remediation efforts. Also, see Note 3 to the financial statements of Southern Company, Georgia Power and Mississippi Power under “Environmental Matters — Environmental Remediation” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Remediation” in Item 8 herein 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 state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state 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 — “PSC Matters” of Southern Company and each of the retail operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” and Note 3 to the financial statements of each of the retail operating companies under “Retail Regulatory Matters” in Item 8 herein for a discussion of rate matters. Also, see Note 1 to the financial statements of Southern Company and each of the retail operating companies in Item 8 herein for a discussion of recovery of fuel costs and environmental compliance costs through rates.

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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 any new demand-side or supply-side resources. Once certified, the lesser of actual or certified construction costs and purchased 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 for Plant Goat Rock, units 1 and 2. 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. The purchase of the full 610 megawatts from the second unit began in 2004. 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 a PPA between Duke Energy and Georgia Power for 620 megawatts for seven years that began in June 2005.
     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 supply-side certification conducted in 2002 and, at the same time, the Georgia PSC also approved the de-certification of Savannah Electric’s Plant Riverside, units 4 through 8, effective in May 2005. The McIntosh units 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 became available in June 2005. See Note 3 to the financial statements of Georgia Power and Savannah Electric under “Retail Regulatory Matters — Plant McIntosh Construction Project” in Item 8 herein for additional information.
     Georgia Power and Savannah Electric received Georgia PSC approval of the 2004 IRP in July 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 and Savannah Electric extended the life of the Kraft combustion turbine unit until such time as its retirement is warranted. Georgia Power and Savannah Electric issued an RFP in July 2005 for approximately 1,000 megawatts to meet their future supply-side capacity needs for 2009 and beyond. With the planned merger of Savannah Electric into Georgia Power, this RFP will be consolidated by Georgia Power which will be the sole party to these contracts. In March 2006, Georgia Power is scheduled to issue RFPs for approximately 2,100 and 1,400 megawatts, respectively, to meet its 2010 and 2011 supply-side needs. For the 2011 RFP, Georgia Power will submit a self-build proposal that compares to the market. Additionally, Georgia Power and, until completion of the planned merger, 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 eight megawatts of capacity from existing qualifying facilities under firm contracts and continue to add additional resources as ordered by the Georgia PSC.
     In January 2006, Georgia Power filed an application with the Georgia PSC to approve an amendment to Georgia Power’s IRP in connection with the merger to add Savannah Electric customers and generating assets.
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 EARNINGS POTENTIAL — “PSC Matters — Alabama Power” and “PSC Matters — Retail Rate Adjustments,” respectively, of Southern Company and Alabama Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Alabama Power, under “Alabama Power Retail Regulatory Matters” and “Retail Regulatory Matters,” respectively, in Item 8 herein for a discussion on Alabama PSC rate matters.

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     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 under “Retail Regulatory Matters” in Item 8 herein 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 2006 ECO Plan in February 2006, which, if approved as filed, will result in a decrease in customer prices. See Note 3 to the financial statements of Mississippi Power under “Environmental Compliance Overview Plan” in Item 8 herein for additional information.
Storm Damage Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters - Storm Damage Recovery” of Southern Company, Gulf Power and Mississippi Power and “PSC Matters — Natural Disaster Cost Recovery” of Alabama Power in Item 7 herein and to Note 3 to the financial statements of Southern Company, Alabama Power, Gulf Power and Mississippi Power under “Storm Damage Cost Recovery,” “Retail Regulatory Matters — Natural Disaster Cost Recovery,” “Retail Regulatory Matters — Storm Damage Cost Recovery” and “Retail Regulatory Matters — Storm Damage Cost Recovery,” respectively, in Item 8 herein for a discussion of the impacts and recovery of storm damage costs related to Hurricanes Ivan, Dennis and Katrina.
Employee Relations
The Southern Company system had a total of 25,554 employees on its payroll at December 31, 2005.
         
    Employees
    at
    December 31, 2005
Alabama Power
    6,621  
Georgia Power
    8,713  
Gulf Power
    1,335  
Mississippi Power
    1,254  
Savannah Electric
    560  
SCS
    3,415  
Southern Company Gas
    *  
Southern Holdings**
    11  
Southern Nuclear
    3,101  
Southern Power
    ***  
Other
    544  
 
Total
    25,554  
 
 
*   Southern Company Gas has no employees. Southern Company Gas has agreements with SCS and Georgia Power whereby employee services are rendered at cost.
 
**   One of Southern Holdings’ subsidiaries has 11 employees. Southern Holdings has agreements with SCS whereby all other employee services are rendered at cost.
 
***   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.

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     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, 2008.
     Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through October 14, 2009.
     Mississippi Power has an agreement with the IBEW on a four-year contract extending to August 16, 2006. Negotiations on a new agreement are expected to begin in July 2006.
     Savannah Electric has agreements with the IBEW and the Office and Professional Employees International Union that expire April 15, 2006 and December 1, 2006, respectively. The status of these agreements is expected to be negotiated and resolved prior to the completion of the merger of Savannah Electric with and into Georgia Power by July 2006.
     Southern Nuclear has agreements with the IBEW on a three-year contract extending to June 30, 2008 for Plants Hatch and Vogtle and a five-year contract which expires August 15, 2006 for Plant Farley. Negotiations on the Plant Farley contract are expected to begin in June 2006. 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 1A. RISK FACTORS
In addition to the other information in this Form 10-K, including MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, 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.
Risks Related to the Energy Industry
Southern Company and its subsidiaries are 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 and its subsidiaries.
     Southern Company and its subsidiaries, including the retail operating companies and Southern Power, are 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. While the retail rates approved by the respective state PSCs are designed to provide for recovery of costs and a return on invested capital, there can be no assurance that a state PSC will not deem certain costs to be imprudently incurred and not subject to recovery.
     Until February 8, 2006, Southern Company was subject to regulation by the SEC under the Holding Company Act. In July 2005, the U.S. Congress passed the Energy Act of 2005 which, among other things, repealed the Holding Company Act effective February 8, 2006. Under the Energy Act of 2005, the FERC was provided with new oversight responsibilities for the electric utility industry.
     Southern Company and its subsidiaries believe the necessary permits, approvals and certificates have been obtained for its existing operations and that their respective businesses are conducted in accordance with applicable laws; however, 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 the operating environment of Southern Company and its subsidiaries and may result in substantial costs.
General Risks Related to Operation of Southern Company’s Utility Subsidiaries
The regional power market in which Southern Company and its utility subsidiaries compete may have 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. Since 1999, when the FERC issued final rules on RTOs, there have been a number of proceedings at FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. Under this new transmission regulatory structure, the retail operating companies could transfer functional control (but not ownership) of their transmission facilities to an independent third party. While there are no active proceedings at FERC that would require Southern Company to participate in a 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. The financial condition, net income and cash flows of Southern Company and its utility subsidiaries

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could be adversely affected by future changes in the federal regulatory or operational structure of transmission.
Certain events in the energy markets that are beyond the control of Southern Company and its subsidiaries 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 the business operations or the accounting treatment of the existing operations of Southern Company and its subsidiaries which could have a negative impact on the net income or access to capital of Southern Company and its subsidiaries.
     As a result of the energy crisis in California during the summer of 2001, the Enron Corporation bankruptcy, 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. This increased scrutiny has led to substantial changes in laws and regulations affecting Southern Company and its subsidiaries, including, among others, enhanced internal control and auditor independence requirements, financial statement certification requirements, more frequent SEC reviews of financial statements and accelerated and additional SEC filing requirements. New accounting and disclosure requirements have changed the way Southern Company and its subsidiaries are required to record revenues, expenses, assets and liabilities. Southern Company expects continued regulatory focus on accounting and financial reporting issues. Future disruptions in the industry such as those described above and any additional resulting regulations may have a negative impact on the net income or access to capital of Southern Company and its subsidiaries.
Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs which could negatively impact the net income of Southern Company and the retail operating companies and the value of their respective 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 and the retail operating companies cannot predict if or when they may be subject to changes in legislation or regulation, nor can Southern Company and the retail operating companies predict the impact of these changes.
     Additionally, the electric utility industry has experienced a substantial increase in competition at the wholesale level. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. In addition, FERC rules on transmission service are designed to facilitate competition in the wholesale market on a nationwide basis, by providing 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 December 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 an issue in that proceeding. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event

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that FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than market-based rates.
     In addition, in May 2005 the FERC started an investigation to determine whether Southern Company satisfies the other three parts of FERC’s market-based rate analysis: transmission market power, barriers to entry and affiliate abuse or reciprocal dealing. Any and all new market-based rate transactions involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the refund period beginning July 19, 2005.
     In May 2005, the FERC also initiated a proceeding to examine the provisions of the IIC, whether any parties to the IIC have violated FERC’s standards of conduct applicable to utility companies that are transmission providers, and whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent FERC orders any changes to the IIC.
Risks Related to Environmental Regulation
Southern Company’s and the retail operating companies’ costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws and the incurrence of environmental liabilities could harm the net income and cash flows of Southern Company, the retail operating companies or Southern Power.
     Southern Company and the retail operating companies 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 and the retail operating companies to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of their respective facilities. These expenditures are significant and Southern Company and the retail operating companies expect that they will increase in the future. Through 2005, Southern Company had spent approximately $1.6 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2 and NOx emissions, to maintain compliance with existing regulations and to meet new requirements.
     Approximately $1.3 billion of these expenditures related to reducing NOx emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NOx reduction rules.
     Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, such as opacity and other air quality standards, 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.
     If Southern Company, the retail operating companies or Southern Power fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in the assessment of civil or criminal penalties and fines. 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. Georgia Power is a party to a civil suit regarding alleged violations of the Clean Air Act at four units of Plant Wansley, and Southern Company is a party to a suit alleging its emissions of carbon dioxide, a greenhouse gas, contribute to global warming. 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 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.
     Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be

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adopted or become applicable to Southern Company, the retail operating companies and Southern Power. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on the facilities of the retail operating companies or Southern Power or increased compliance costs which may not be fully recoverable from customers and would therefore reduce the net income of Southern Company, the retail operating companies or Southern Power. 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 net income and cash flows of its subsidiaries and their ability to pay upstream dividends or to repay funds to Southern Company. Prior to funding Southern Company, Southern Company’s subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends.
The financial performance of Southern Company and its subsidiaries 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 or material 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 the net income and cash flows and could adversely impact the financial condition of the affected retail operating company or Southern Power and of Southern Company.
     In addition, Southern Company’s non-utility businesses depend on the successful operation of their respective facilities. For example, the net income and cash flows of SouthernLINC Wireless and Southern Company could be adversely impacted in the event of a major failure of its telecommunications facilities.
The revenues of Southern Company, the retail operating companies and Southern Power 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 the net income and cash flows of the affected retail operating company or Southern Power and of Southern Company.
     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 enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these 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 the net income and cash flows of the affected retail operating company or Southern Power and of Southern Company. Although these credit evaluations take into account the possibility of default by a purchaser, 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.

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Southern Company, the retail operating companies and Southern Power may incur additional costs or delays in power plant construction and may not be able to recover their investment. The facilities of Southern Company, the retail operating companies and Southern Power 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 facility or 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 net income and financial position of a retail operating company or Southern Power and Southern Company. Furthermore, if construction projects are not completed according to specification, a retail operating company or Southern Power and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income.
     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 owned by the retail operating companies and Southern Power less competitive.
     A key element of the business model of Southern Company, the retail operating companies and Southern Power 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, the market share of Southern Company, the retail operating companies and Southern Power could be eroded, and the value of their respective electric generating facilities could be reduced. Changes in technology could also alter the channels through which retail electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the retail operating companies or Southern Power.
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 owned by Alabama Power or Georgia Power, and which may present potential exposures in excess of insurance coverage.
     Alabama Power owns two nuclear units and Georgia Power holds undivided interests in, and contracts for operation of, four nuclear units. These six units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 9.1% of Southern Company’s generation capacity as of December 31, 2005. These 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. Alabama Power and Georgia Power

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maintain 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 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 Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, although Alabama Power, Georgia Power and Southern Company have no reason to anticipate a serious nuclear incident at its plants, if an incident did occur, it could result in substantial costs to Alabama Power or Georgia Power and 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.
     In addition, potential terrorist threats and increased public scrutiny of utilities could result in increased nuclear licensing or compliance costs that are difficult or impossible to predict.
The generation and energy marketing operations of Southern Company, the retail operating companies and Southern Power are subject to risks, many of which are beyond their control, including changes in power prices and fuel costs, that may reduce Southern Company’s, the retail operating companies’ and Southern Power’s revenues and increase costs.
     The generation and energy marketing operations of Southern Company, the retail operating companies and Southern Power are subject to changes in power prices or fuel costs, which could increase the cost of producing power or decrease the amount Southern Company, the retail operating companies and Southern Power receive from the sale of power. The market prices for these commodities may fluctuate over relatively short periods of time. Southern Company, the retail operating companies and Southern Power attempt to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers through the retail operating company fuel cost recovery clauses or through 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 the generation facilities of the retail operating companies, Southern Power and Southern Company, 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 the expenses of the retail operating companies or Southern Power and Southern Company. For the retail operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the retail operating companies or Southern Power and Southern Company.
     As a result of increasing fuel costs, the retail operating companies have accrued significant underrecovered fuel cost balances. In addition, Alabama Power, Gulf Power and Mississippi Power have significant deficit balances in their storm cost recovery reserves as a result of Hurricanes Ivan, Dennis and Katrina. While the retail operating companies are generally authorized under state legislation administered by the

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respective PSCs to recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs through special rate provisions, recovery may be denied if costs are deemed to be imprudently incurred and delays in the authorization of such recovery could negatively impact the cash flows of the affected retail operating companies and Southern Company.
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 net income of Southern Company and its subsidiaries.
     Southern Company and its subsidiaries, including the retail operating companies and Southern Power, 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.
The retail operating companies and Southern Power may not be able to obtain adequate fuel supplies, which could limit their ability to operate their facilities.
     The retail operating companies and Southern Power purchase fuel, including coal, natural gas and fuel oil, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, weather, labor relations, force majuere events or environmental regulations affecting any of these fuel suppliers, could limit the ability of the retail operating companies and Southern Power to operate their respective facilities, and thus, reduce the net income of the affected retail operating company or Southern Power and Southern Company.
     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. 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.
     In addition, Southern Power in particular, and the retail operating companies to a lesser extent, are dependent on natural gas for a portion of their electric generating capacity. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed. For example, in connection with the 2005 hurricanes in the Gulf of Mexico, production and distribution of natural gas was limited for a period of time, resulting in shortages and significant increases in the price of natural gas. In addition, world market conditions for fuels, including the policies of the Organization of Petroleum Exporting Companies, can impact the price and availability of natural gas.
Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation capabilities.
     Through the retail operating companies and Southern Power, Southern Company is currently obligated to supply power to retail customers 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 the retail operating companies or Southern Power 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

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Power would not have the ability to recover any of these costs. These situations could have negative impacts on net income and cash flows for the affected retail operating company or Southern Power and Southern Company.
The operating results of Southern Company, the retail operating companies and Southern Power 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, the overall operating results of Southern Company, the retail operating companies and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the retail operating companies and Southern Power have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, available cash and borrowing ability of Southern Company, the retail operating companies and Southern Power.
Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation have filed a claim against Southern Company seeking substantial monetary damages in connection with transfers made by Mirant to Southern Company prior to the Mirant spin-off.
     In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code, and in January 2006, completed its plan of reorganization.
     In 2005, Mirant, as debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company in 1999 and 2000 with actual intent to hinder, delay or defraud creditors, or, alternatively, when Southern Company knew or should have known that Mirant was allegedly insolvent, undercapitalized or unable to pay its debts. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees and costs. In addition, Mirant has objected to Southern Company’s claims against Mirant in the Bankruptcy Court and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. While Southern Company believes there is no meritorious basis for Mirant’s claims and intends to vigorously defend itself in the action, the ultimate outcome of Mirant’s claims cannot be determined at this time.
IRS challenges to Southern Company’s income tax deductions taken in connection with four international leveraged lease transactions could result in the payment of substantial additional interest and penalties and could materially impact Southern Company’s cash flow and net income.
     Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. In connection with its audit of Southern Company’s tax returns for 1996 through 2001, the IRS proposed to disallow Southern Company’s tax losses related to one international leveraged lease (a lease-in-lease-out, or LILO) transaction. In February 2005, Southern Company reached a negotiated settlement with the IRS relating to this matter, which is subject to final approval.
     In addition, the IRS has challenged Southern Company’s deductions related to the three other international leases (sale-in-lease-out, or SILO) transactions in connection with its audit of Southern Company’s 2000 and 2001 tax returns. 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 $34 million, and the IRS has proposed a penalty of approximately $16 million. 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 has recently proposed changes to the accounting for both leveraged leases and uncertain tax positions that are expected to become effective in 2006. For the LILO transaction, Southern

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Company’s estimates the cumulative effect upon adoption of the accounting change would reduce Southern Company’s net income by approximately $16 million. The impact of these proposed changes related to the SILO transactions would be dependent on the outcome of ongoing negotiations with the IRS, but could be significant, and potentially material, to Southern Company’s net income.
Risks Related to Market and Economic Volatility
The business of Southern Company, the retail operating companies and Southern Power is dependent on their ability to successfully access capital markets. The inability of Southern Company, any retail operating company or Southern Power to access capital may limit its ability to execute its business plan or pursue improvements and make acquisitions that Southern Company, the retail operating companies or Southern Power may otherwise rely on for future growth.
     Southern Company, the retail operating companies and Southern Power rely 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 their respective operations. If Southern Company, any retail operating company or Southern Power 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, the retail operating companies or Southern Power may otherwise rely on for future growth will be limited. Each of Southern Company, each retail operating company and Southern Power believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of the credit rating of Southern Company, any retail operating company or Southern Power 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, the retail operating companies and Southern Power are subject to risks associated with a changing economic environment, including their ability to obtain insurance, the financial stability of their respective customers and their 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, the retail operating companies, Southern Power and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the retail operating companies and Southern Power are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. Any economic downturn or disruption of financial markets could constrain the capital available to Southern Company’s, the retail operating companies’ and Southern Power’s industry and could reduce access to funding for the respective operations of Southern Company, the retail operating companies and Southern Power, as well as the financial stability of their respective 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 net income.
Certain of the retail operating companies have substantial investments in the Gulf Coast region which can be subject to major storm activity. The ability of the retail operating companies to recover costs and replenish reserves in the event of a major storm, other natural disaster, terrorist attack or other catastrophic event generally will require regulatory action.
     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 generating facilities and other property. In September 2004, Hurricane Ivan hit the Gulf coast of Florida and Alabama, causing significant damage to the service areas of Alabama Power and Gulf Power. In July and August

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2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf coast of the United States and caused significant damage in the service areas of Gulf Power, Alabama Power and Mississippi Power. In each case, costs to the respective retail operating companies exceeded their respective storm cost reserves and insurance coverage. In the event a retail operating company experiences a natural disaster, terrorist attack or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of the respective state PSC. While the retail operating companies generally are entitled to recover prudently incurred costs incurred in connection with such an event, any denial by the state PSC or delay in recovery of any portion of such costs could have a material negative impact on a retail operating company’s result of operations and/or cash flows.
Increases in the price of oil may limit tax credits available to Southern Company under Section 29 of the Internal Revenue Code in connection synthetic fuel investments and could result in impairments to Southern Company’s investments in synthetic fuel projects.
     Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the Internal Revenue Code. 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 require an impairment analysis of these investments by Southern Company.
Item 1B. UNRESOLVED STAFF COMMENTS.
None.

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Item 2. PROPERTIES
Electric Properties – The Electric Utilities
The retail operating companies, Southern Power and SEGCO, at December 31, 2005, owned and/or operated 34 hydroelectric generating stations, 31 fossil fuel generating stations, three nuclear generating stations and 11 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  
 
         
Savannah Electric Total
        444,253  
 
         
 
           
Gaston Units 1-4
  Wilsonville, AL        
SEGCO Total
        1,000,000 (7)
 
         
Total Fossil Steam
        21,150,465  
 
         
 
           
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     756,000  
Oleander
  Cocoa, FL     628,400  
 
         
Southern Power Total
        1,384,400  
 
           
Gaston (SEGCO)
  Wilsonville, AL     19,680 (7)
 
         
Total Combustion Turbines
        4,430,221  
 
         
 
           
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  
 
         
 
           
McIntosh Units 10&11
  Effingham County, GA        
Georgia Power Total
        1,106,178 (13)
 
         
 
           
Smith
  Lynn Haven, FL        
Gulf Power Total
        545,500  
 
         
 
           
Daniel (Leased)
  Pascagoula, MS        
Mississippi Power Total
        1,070,424  
 
         
 
           
McIntosh Units 10&11
  Effingham County, GA        
Savannah Electric Total
        212,742 (13)
 
         
 
           
Stanton Unit A
  Orlando, FL     428,649 (14)
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
        8,024,197  
 
         
 
           
HYDROELECTRIC FACILITIES
           
 
           
Bankhead
  Holt, AL     53,985  
Bouldin
  Wetumpka, AL     225,000  
Harris
  Wedowee, AL     132,000  
Henry
  Ohatchee, AL     72,900  
Holt
  Holt, AL     48,000  
Jordan
  Wetumpka, AL     100,000  
Lay
  Clanton, AL     177,000  
Lewis Smith
  Jasper, AL     157,500  
Logan Martin
  Vincent, AL     135,000  
Martin
  Dadeville, AL     182,000  
Mitchell
  Verbena, AL     170,000  
Thurlow
  Tallassee, AL     81,000  
Weiss
  Leesburg, AL     87,750  
Yates
  Tallassee, AL     47,000  
 
         
Alabama Power Total
        1,669,135  
 
         
 
           
Barnett Shoals (Leased)
  Athens, GA     2,800  
Bartletts Ferry
  Columbus, GA     173,000  
Goat Rock
  Columbus, GA     38,600  
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
        1,090,336  
 
         
Total Hydroelectric Facilities
        2,759,471  
 
         
 
           
Total Generating Capacity
        40,508,852  
 
         
 
Notes:    
 
(1)   See “Jointly-Owned Facilities” 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.

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(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. Progress Energy 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 Georgia Power’s portion (83.87%) and Savannah Electric’s portion (16.13%), respectively, of total plant capacity.
 
(14)   Capacity shown is Southern Power’s portion (65%) of total plant capacity.
     Except as discussed below under “Titles to Property,” the principal plants and other important units of the retail operating companies, Southern Power and 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, 2005, the unamortized portion of this cost was approximately $27.7 million.
     The all-time maximum demand on the retail operating companies, Southern Power and SEGCO was 35,049,600 kilowatts and occurred on July 26, 2005. This amount excludes demand served by capacity retained by MEAG, OPC and SEPA. The reserve margin for the retail operating companies, Southern Power and SEGCO at that time was 14.4%. 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                           Progress   Southern            
    Capacity   Power   AEC   Power   OPC   MEAG   DALTON   Energy   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 five 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

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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.
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 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 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 “Jointly-Owned Facilities” 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 “Environmental Matters — 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)   Environmental Remediation
 
    See “Environmental Matters — 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.
 
(3)   In re: Mirant Corporation, et al.
(U.S. Bankruptcy Court for the Northern District of Texas)
 
    See “Mirant Matters — Mirant Bankruptcy” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
 
(4)   MC Asset Recovery, LLC v. Southern Company
(in process of transfer to the U.S. District Court for the Northern District of Georgia from the U.S. District Court for the Northern District of Texas) (formerly styled In re: Mirant Corporation, et al. in the U.S. Bankruptcy Court for the Northern District of Texas)
 
    See “Mirant Matters — Mirant Bankruptcy Litigation” 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 Matters — 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 “Mirant Matters — 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.
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.
Southern Company, Alabama Power, Georgia Power, Mississippi Power, Savannah Electric and Southern Power
None.
Gulf Power
On October 27, 2005, in an action taken by written consent, Southern Company as the sole shareholder of Gulf Power at that time, approved a plan of domestication under which Gulf Power, originally formed under the laws of the State of Maine on November 2, 1925, was domesticated as a Florida corporation, effective at 12:01 a.m. Eastern Standard Time on November 2, 2005. Under applicable law, the domestication does not affect the inception date of Gulf Power nor does it affect any obligations or liabilities of Gulf Power incurred prior to its domestication.
     In connection with the domestication, on October 27, 2005, Southern Company as the sole shareholder of Gulf Power at that time, in actions taken by written consent, also approved amended and restated Articles of Incorporation of Gulf Power and adopted amendments to the bylaws of Gulf Power. The amended and restated Articles of Incorporation were filed with the Florida Secretary of State on October 27, 2005 and such Articles and the amended bylaws became effective on November 2, 2005.

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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, 2005.
David M. Ratcliffe
Chairman, President, Chief Executive Officer and
Director
Age 57
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.
Andrew J. Dearman, III
Executive Vice President
Age 52
Elected in 2005. Executive Vice President since December 2005. Previously served as Senior Vice President from December 2000 until December 2005.
Dwight H. Evans
Executive Vice President
Age 57
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 48
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 56
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; and Executive Vice President — Customer Service of Alabama Power from January 2000 to May 2001.
G. Edison Holland, Jr.
Executive Vice President
Age 53
Elected in 2001. Executive Vice President since 2001. Previously served as Director, President and Chief Executive Officer of Savannah Electric from 1997 until 2001.
Anthony R. James
Executive Vice President
Age 55
Elected in 2005. Executive Vice President of Southern Company since December 2005. Previously served as Chairman of Savannah Electric from December 2005 through January 2006; President and Chief Executive Officer of Savannah Electric from April 2001 to December 2005 and Vice President of Savannah Electric from July 2000 until April 2001.
Charles D. McCrary
Executive Vice President
Age 54
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
Executive Vice President of SCS
Age 49
Elected in 2001. Executive Vice President of SCS since May 2001 and previously served as President and Chief Executive Officer of Southern Power from May 2001 to March 2005. He also previously served as Senior Vice President and Chief Marketing Officer of Southern Company from March 2000 to May 2001.
J. Barnie Beasley
President and Chief Executive Officer of Southern Nuclear
Age 54
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.

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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 25, 2005) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified, except for Messrs. Dearman and James, whose elections were effective December 12, 2005.

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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, 2005.
Charles D. McCrary
President, Chief Executive Officer and Director
Age 54
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 51
Elected in 2004. Executive Vice President, Chief Financial Officer and Treasurer since February 2005. Previously served as Vice President and Comptroller of Alabama Power from 1998 through January 2005.
C. Alan Martin
Executive Vice President
Age 57
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 50
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.
Jerry L. Stewart
Senior Vice President
Age 56
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 organizational meeting of the directors (April 22, 2005) for one year until the next annual meeting or until their successors are elected and have qualified.

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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, 2005.
Anthony J. Topazi
President, Chief Executive Officer and Director
Age 55
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 2003; Senior Vice President of Southern Power from November 2002 to December 2003; and Vice President of Southern Power from 2001 until November 2002.
John W. Atherton
Vice President
Age 45
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 41
Elected in 2005. Vice President and Senior Production Officer since March 2005. Previously served as Plant Manager, Plant Bowen, Georgia Power from November 2000 until March 2005.
Bobby J. Kerley
Vice President
Age 52
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.
Frances Turnage
Vice President, Treasurer and
Chief Financial Officer
Age 57
Elected in 2005. Vice President, Treasurer and Chief Financial Officer since March 2005. Previously served as Comptroller from 1993 to March 2005.
     The officers of Mississippi Power were elected for a term running from the last annual organizational meeting of the directors (April 27, 2005) for one year until the next annual meeting or until their successors are elected and have qualified.

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PART II
Item 5.   MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
  (a)   The common stock of Southern Company is listed and traded on the New York Stock Exchange. The common 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
2005
               
First Quarter
  $ 34.08     $ 31.25  
Second Quarter
    34.91       31.78  
Third Quarter
    36.16       33.47  
Fourth Quarter
    36.07       33.28  
 
               
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  
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, 2005: 118,285
 
      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   2005   2004
        (in thousands)
Southern Company  
First
  $ 265,958     $ 257,506  
   
Second
    277,679       258,318  
   
Third
    277,625       264,051  
   
Fourth
    276,306       264,859  
   
 
               
Alabama Power  
First
  $ 102,475     $ 109,325  
   
Second
    102,475       109,325  
   
Third
    102,475       109,325  
   
Fourth
    102,475       109,325  
   
 
               
Georgia Power  
First
  $ 139,025       141,375  
   
Second
    139,025       141,375  
   
Third
    139,025       141,375  
   
Fourth
    139,025       141,375  
   
 
               
Gulf Power  
First
  $ 17,100     $ 17,500  
   
Second
    17,100       17,500  
   
Third
    17,100       17,500  
   
Fourth
    17,100       17,500  
   
 
               
Mississippi Power  
First
  $ 15,500     $ 16,550  
   
Second
    15,500       16,550  
   
Third
    15,500       16,550  
   
Fourth
    15,500       16,550  
   
 
               
Savannah Electric  
First
  $ 6,675     $ 5,800  
   
Second
    6,675       5,800  
   
Third
    6,675       5,800  
   
Fourth
    6,675       5,800  
 
In 2004 and 2005, Southern Power paid $320 million and $72.4 million, respectively, in dividends to Southern Company.
The dividend paid per share of Southern Company’s common stock was 35¢ for the first two quarters of 2004 and 35.75¢ for the last two quarters of 2004 and first quarter of 2005 and 37.25¢ for the second, third and fourth quarters of 2005.

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At December 31, 2005, in accordance with its first mortgage bond indenture, $68 million of Savannah Electric’s retained earnings was restricted against payment of cash dividends. Southern Power’s credit facility contains potential limitations on the payment of common stock dividends. At December 31, 2005, Southern Power was in compliance with the conditions of this credit facility and thus had no restrictions on its ability to pay common stock dividends. See Note 8 to the financial statements of Southern Company under “Common Stock Dividend Restrictions,” Note 6 to the financial statements of Savannah Electric under “Common Stock Dividend Restrictions” and Note 5 to the financial statements of Southern Power under “Dividend Restriction” in Item 8 herein for additional information regarding these restrictions.
(d) Issuer Purchases of Equity Securities
                                 
                            Maximum
                    Total   Approximate
                    Number   Dollar
                    Of Shares   Value
                    Purchased   Of Shares
                    As Part   That
    Total   Average   Of   May Yet
    Number   Price   Publicly   Be Purchased
    Of   Paid   Announced   Under the
    Shares   Per   Plans or   Plans or
2005   Purchased   Share   Programs   Programs (1)
October 1-31
    191,417     $ 34.19       191,417       N/A  
November 1-30
    40,241     $ 34.46       40,241       N/A  
December 1-31
    94,333     $ 35.04       94,333       N/A  
Total
    325,991     $ 34.47       325,991       N/A  
 
(1) As announced in 2004, in May 2005, Southern Company engaged an agent to (i) begin repurchasing shares of Southern Company common stock to offset the 6,273,876 shares of common stock issued from January 2005 through May 2005 in connection with the exercise of stock options under the Omnibus Plan and (ii) repurchase shares of Southern Company common stock on an ongoing basis to offset additional shares issued in connection with the exercise of stock options under the Omnibus Plan. As of December 31, 2005, Southern Company has repurchased a total of 10,066,958 shares. The repurchase program was discontinued in early January 2006.
Item 6.   SELECTED FINANCIAL DATA
     Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-77 and II-78.
     Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-128 and II-129.
     Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-185 and II-186.
     Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-233 and II-234.
     Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-284 and II-285.
     Savannah Electric. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-331 and II-332.
     Southern Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at page II-362.
Item 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     Southern Company. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-11 through II-37.
     Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-81 through II-99.
     Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-132 through II-151.
     Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-189 through II-207.
     Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-237 through II-256.

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     Savannah Electric. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-288 through II-305.
     Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-335 through II-347.
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 under “Financial Instruments” in Item 8 herein. 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 under “Financial Instruments” in Item 8 herein.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2005 FINANCIAL STATEMENTS
         
    Page  
The Southern Company and Subsidiary Companies:
       
  II-8
   
  II-9
  II-10
  II-38
  II-39
  II-41
  II-42
  II-44
  II-44
  II-45
 
       
Alabama Power:
       
  II-80
  II-100
  II-101
  II-102
  II-104
  II-106
  II-106
  II-107
 
       
Georgia Power:
       
  II-131
  II-152
  II-153
  II-154
  II-156
  II-157
  II-157
  II-158
 
       
Gulf Power:
       
  II-188
  II-208
  II-209
  II-210
  II-212
  II-213

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    Page  
  II-213
  II-214
 
       
Mississippi Power:
       
  II-236
  II-257
  II-258
  II-259
  II-261
  II-262
  II-262
  II-263
 
       
Savannah Electric:
       
  II-287
  II-306
  II-307
  II-308
  II-310
  II-311
  II-311
  II-312
 
       
Southern Power and Subsidiary Companies:
       
  II-334
  II-348
  II-349
  II-350
  II-352
  II-352
  II-353
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.

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Item 9A.   CONTROLS AND PROCEDURES
Disclosure Controls And Procedures.
     As of the end of the period covered by this annual report, Southern Company, the retail operating companies and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and 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.
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 2005 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
          During the fourth quarter 2005, Savannah Electric transferred responsibility for certain internal control procedures related to accounting for property, joint ownership, fuel and purchased power transactions to Georgia Power. Savannah Electric continues to review such accounting transactions and maintains overall financial reporting responsibility; however, the transfer of these control procedures constitutes a change 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) that has materially affected or is reasonably likely to materially affect Savannah Electric’s internal control over financial reporting.
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 2005 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, 2005.
     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, 2005. 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 27, 2006

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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, 2005, 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, 2005, 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, 2005, 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, 2005 of the Company and our report dated February 27, 2006 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

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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, 2005 and 2004, 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, 2005. 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, such consolidated financial statements (pages II-38 to II-75) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
     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, 2005, 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 27, 2006 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 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2005 Annual Report
OVERVIEW
Business Activities
The primary business of Southern Company (the Company) 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 constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market.
     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 rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration following multiple hurricanes. Since the beginning of 2004, each of the retail operating companies completed successful retail rate proceedings. These regulatory actions are expected to benefit future earnings stability and 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. In addition, Georgia Power, Gulf Power, and Mississippi Power expect further rate proceedings in 2006 as necessary to address fuel and storm damage cost recovery.
     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 2005 by signing several wholesale contracts with major utilities, as well as with cooperatives and municipal suppliers in the Southeast. 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 fuel producing entities, which claim federal income tax credits that offset their operating losses, leveraged lease projects, telecommunications, and energy-related services. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly. In January 2006, the sale of the Company’s natural gas marketing business was completed.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to more than 4 million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, 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 customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro 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. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects. The 2005 Peak Season EFOR performance was slightly below target (as shown in the chart below) primarily due to an outage event at a combined cycle unit. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2005 performance was above target on these reliability measures. EPS is the measure for Southern Company’s efforts to increase returns to shareholders through average long-term earnings per share growth of 5 percent.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
     Southern Company’s 2005 results compared with its targets for some of these key indicators are reflected in the following chart:
                 
 
  Key Performance     2005 Target     2005 Actual  
  Indicator     Performance     Performance  
  Customer
Satisfaction
    Top quartile in
customer surveys
    Top quartile
 
 
Peak Season EFOR
    2.75% or less     2.83%  
 
EPS
    $2.04 - $2.09     $2.14  
 
     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.
Earnings
Southern Company’s financial performance in 2005 remained strong, despite the challenges of rising costs and major hurricanes. Net income was $1.59 billion in 2005, an increase of 3.8 percent over the prior year. Net income was $1.53 billion in 2004 and $1.47 billion in 2003, reflecting increases over the prior year of 4.0 percent and 11.8 percent, respectively. Basic EPS, including discontinued operations, was $2.14 in 2005, $2.07 in 2004, and $2.03 in 2003. Diluted EPS, which factors in additional shares related to stock options, was 1 cent lower than basic EPS each year.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.475 in 2005, $1.415 in 2004, and $1.385 in 2003. In January 2006, Southern Company declared a quarterly dividend of 37.25 cents per share. This is the 233rd 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 approximately 70 percent of net income, excluding earnings from synthetic fuel businesses. For 2005, the actual payout ratio was 73 percent excluding synthetic fuel earnings, and 69 percent overall.
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  
    2005     2005     2004     2003  
    (in millions)
Electric operating revenues
  $ 13,278     $ 1,813     $ 718     $ 541  
 
Fuel
    4,488       1,089       400       213  
Purchased power
    731       88       170       24  
Other operation and maintenance
    3,220       215       148       105  
Depreciation and amortization
    1,137       229       (64 )     (16 )
Taxes other than income taxes
    676       52       40       29  
 
Total electric operating expenses
    10,252       1,673       694       355  
 
Operating income
    3,026       140       24       186  
Other income, net
    62       38       22       20  
Interest expenses
    676       62       19       10  
Income taxes
    899       24       30       68  
 
Net income
  $ 1,513     $ 92     $ (3 )   $ 128  
 
Revenues
Details of electric operating revenues are as follows:
                         
    2005     2004     2003  
            (in millions)        
Retail — prior year
  $ 9,732     $ 8,875     $ 8,728  
Change in –
                       
Base rates
    236       41       75  
Sales growth
    184       216       104  
Weather
    34       48       (135 )
Fuel and other cost recovery clauses
    979       552       103  
 
Retail current year
    11,165       9,732       8,875  
 
Sales — for resale
    1,667       1,341       1,358  
Other electric operating revenues
    446       392       514  
 
Electric operating revenues
  $ 13,278     $ 11,465     $ 10,747  
 
Percent change
    15.8 %     6.7 %     5.3 %
 
     Retail revenues increased $1.4 billion in 2005, $857 million in 2004, and $147 million in 2003. The

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Southern Company and Subsidiary Companies 2005 Annual Report
significant factors driving these changes are shown in the preceding table. The increase in base rates in 2005 is primarily due to approval by the Georgia Public Service Commission (PSC) of retail base rate increases at Georgia Power and Savannah Electric. 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, storm damage, new plants, and/or purchased power agreements (PPAs).
     Sales for resale revenues increased $326 million in 2005, decreased $17 million in 2004, and increased $190 million in 2003. In 2005, sales for resale revenues increased primarily due to a 26.5 percent increase in the average cost of fuel per net kilowatt-hour (KWH) generated. In addition, Southern Company entered into new PPAs with 30 electric membership cooperatives (EMCs) and Flint EMC, both beginning in January 2005, and in June 2005, in connection with the acquisition of Plant Oleander, assumed two PPAs. In 2004, coal and gas prices increased, resulting in a lower marginal price differential that reduced demand. Mild summer weather throughout the Southeast also reduced demand. In 2003, Southern Company entered into several new PPAs 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.
     Southern Company’s average wholesale contract now extends more than 11 years, and as a result, the Company has significantly limited its remarketing risk. Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect the recovery of fixed costs and a return on investment, and energy is generally sold at variable cost. Unit power energy sales increased 1.7 percent, 1.9 percent, and 4.0 percent in 2005, 2004, and 2003, respectively. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, because the energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The capacity and energy components of the unit power contract revenues were as follows:
                         
    2005     2004     2003  
            (in millions)      
Unit power –
                       
Capacity
  $ 201     $ 185     $ 182  
Energy
    237       213       211  
 
Total
  $ 438     $ 398     $ 393  
 
     Short-term opportunity energy sales are also included in sales for resale. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. Revenues associated with opportunity sales and PPAs were as follows:
                         
    2005     2004     2003  
            (in millions)      
Other power sales –
                       
Capacity and other
  $ 430     $ 308     $ 298  
Energy
    799       635       667  
 
Total
  $ 1,229     $ 943     $ 965  
 
     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. KWH sales for 2005 and the percent change by year were as follows:
                                 
    Amount     Percent Change  
(billions of KWH)   2005     2005     2004     2003  
 
Residential
    51.1       2.8 %     3.9 %     (1.9 )%
Commercial
    51.9       3.6       3.4       0.3  
Industrial
    55.1       (2.2 )     3.6       1.0  
Other
    1.0       (0.9 )     0.8       (0.2 )
 
Total retail
    159.1       1.2       3.6       (0.2 )
Sales for resale
    37.8       7.3       (13.0 )     24.5  
 
Total
    196.9       2.3       0.1       4.2  
 
     Energy sales in 2005 increased 4.5 billion KWH as a result of sustained economic growth and customer growth of 1.2 percent. Hurricane Katrina dampened customer growth from previous years and was the primary contributor to the decrease in industrial sales in 2005. In addition, in 2005, some Georgia Power industrial customers were reclassified from industrial to commercial to be

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Southern Company and Subsidiary Companies Annual Report
consistent with the rate structure approved by the Georgia PSC resulting in higher commercial sales and lower industrial sales in 2005 when compared with 2004. 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 previous years. Energy sales to retail customers are projected to increase at a compound average annual rate of 1.9 percent during the period 2006 through 2011, assuming normal weather conditions.
     Energy sales for resale increased by 2.6 billion KWH in 2005, decreased 5.3 billion KWH in 2004, and increased by 8.0 billion KWH in 2003. The increase in sales in 2005 is related primarily to the new PPAs discussed above. 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.
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:
                         
    2005   2004   2003
 
Total generation (billions of KWH)
    196       188       189
Sources of generation (percent) —
                       
Coal
    71       69       71
Nuclear
    15       16       16
Gas
    11       12       9
Hydro
    3       3       4
Average cost of fuel per net KWH generated (cents)
    2.39       1.89       1.67
Average cost of purchased power per net KWH (cents)
    7.14       4.48       3.86
     In 2005, fuel and purchased power expenses were $5.2 billion, an increase of $1.2 billion or 29.1 percent above the prior year costs. An additional 7.8 billion KWH were generated in 2005 at a 26.5 percent higher average cost per net KWH generated; however, this lowered requirements to purchase even more expensive electricity from non-affiliates.
     Fuel and purchased power expenses were $4.0 billion in 2004, an increase of $570 million or 16.4 percent above 2003 costs. This increase was the result of a 13.2 percent increase in the average cost per net KWH generated and a 16.1 percent increase in the average cost per KWH purchased.
     Fuel and purchased power expenses were $3.5 billion in 2003, an increase of $237 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.
     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 increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term 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 PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.
Other Operation and Maintenance Expenses
Other operation and maintenance expenses were $3.2 billion, $3.0 billion, and $2.9 billion, increasing $215 million, $148 million, and $105 million in 2005, 2004, and 2003, respectively. Other production expenses increased $58 million and $53 million in 2005 and 2004, respectively, and decreased $27 million in 2003. Production expenses fluctuate from year to year due to variations in outage schedules, flexible spending projects, and normal increases in costs.

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Southern Company and Subsidiary Companies Annual Report
     Administrative and general expenses increased $73 million in 2005 related to a $33 million increase in employee benefits, a $22 million increase in shared services expenses, and a $9 million increase in property insurance. Administrative and general expenses increased $106 million in 2004 primarily related to $41 million, $23 million, and $13 million increases in employee benefits, shared services expenses, primarily nuclear security, and property insurance, respectively. In 2003, administrative and general expenses increased $46 million, due primarily to a $19 million increase in property insurance, a $9 million increase in employee benefits, and $9 million of business development costs at Southern Power.
     Transmission and distribution expenses increased $60 million in 2005, $49 million in 2004, and $23 million in 2003. Transmission and distribution expenses increased in 2005 primarily as a result of $48 million of expenses recorded by Alabama Power in accordance with an accounting order approved by the Alabama PSC primarily to offset the costs of Hurricane Ivan and restore the natural disaster reserve. In accordance with the accounting order, Alabama Power also returned certain regulatory liabilities related to deferred income taxes to its retail customers; therefore, the combined effect of the accounting order had no impact on net income. See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information. Transmission and distribution expenses also fluctuate from year to year due to variations in maintenance schedules, flexible spending projects, and normal increases in costs, and are the primary basis for the 2004 and 2003 increases.
     The 2003 increase in other operation and maintenance expenses also reflects the establishment of a $60 million regulatory liability related to Plant Daniel that was expensed in 2003.
Depreciation and Amortization Expenses
Depreciation and amortization expenses increased $229 million in 2005 as a result of additional plant in service and from the expiration in 2004 of certain provisions in Georgia Power’s retail rate plan for the three years ended December 31, 2004 (2001 Retail Rate Plan). In accordance with the 2001 Retail Rate Plan, Georgia Power amortized an accelerated cost recovery liability as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates over the three years ended December 31, 2004. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.
     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 — “PSC Matters — Mississippi Power” herein and Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for more information on these regulatory adjustments. These reductions were partially offset by a higher depreciable plant base.
     The $16 million decrease in depreciation and amortization expenses 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.
Taxes Other Than Income Taxes
Taxes other than income taxes increased by $52 million in 2005 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales. In 2004, taxes other than income taxes increased $40 million as a result of additional plant in service and a higher property tax base. Taxes other than income taxes increased $29 million in 2003 as a result of additional generating facilities, as well as higher property tax valuations on existing facilities.
Electric Other Income and (Expense)
Total interest charges and other financing costs increased by $62 million in 2005 associated with an additional $863 million in debt outstanding at December 31, 2005 as compared to December 31, 2004 and an increase in average interest rates on variable rate debt. Variable rates on pollution control bonds are highly correlated with the Bond Market Association Municipal Swap Index which averaged 2.5 percent in 2005 and 1.2 percent in 2004. Variable rates on commercial paper and senior notes are highly correlated with the one-month London Interbank Offer Rate (LIBOR), which averaged 3.4 percent in 2005 and 1.5 percent in 2004. An additional $17 million increase in 2005 was the result of a lower percentage of interest costs

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Southern Company and Subsidiary Companies Annual Report
capitalized as construction projects reached completion. The $19 million increase in interest charges and other financing costs in 2004 was also the result of a lower percentage of interest costs capitalized as construction projects reached completion.
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 was a retail gas marketer serving customers in the State of Georgia. On January 4, 2006, Southern Company Gas completed the sale of substantially all of its assets and is reflected in the condensed income statement below as discontinued operations. See Note 3 to the financial statements under “Southern Company Gas Sale” for additional information.
     A condensed income statement for Southern Company’s other business activities follows:
                                 
            Increase (Decrease)
    Amount   from Prior Year
    2005   2005   2004   2003
            (in millions)        
Operating revenues
  $ 276     $ 12     $ (7 )   $ 30  
 
Operation and maintenance
    297       12       28       (23 )
Depreciation and amortization
    39       (2 )     (9 )     (7 )
Taxes other than income taxes
    4       1       1        
 
Total operating expenses
    340       11       20       (30 )
 
Operating income
    (64 )     1       (27 )     60  
Equity in losses of unconsolidated subsidiaries
    (123 )     (26 )     3       (8 )
Leveraged lease income
    74       4       4       8  
Other income, net
    (12 )     (5 )     (15 )     9  
Interest expenses
    101       18       (21 )     6  
Income taxes
    (304 )     (14 )     (63 )     23  
Discontinued operations, net of tax
          (3 )     12       (12 )
 
Net income
  $ 78     $ (33 )   $ 61     $ 28  
 
     Southern Company’s non-electric operating revenues increased $12 million in 2005 primarily as the result of higher production and increased fees in the synthetic fuel business. The $7 million decrease in 2004 was primarily due to lower operating revenues in the energy-related services business, partially offset by an increase in SouthernLINC Wireless revenues as a result of increased wireless subscribers. The $30 million increase in revenues in 2003 was primarily due to increased sales in the energy-related services business. Revenues from a subsidiary that primarily provides fuel transportation services related to synthetic fuel products were $123 million in 2005, increasing by $17 million, $21 million, and $37 million in 2005, 2004, and 2003, respectively, as a result of increased production at the synthetic fuel facilities and annual increases in rates. Most of these service revenues are ultimately included in the cost of the synthetic fuel purchased by Alabama Power and Georgia Power and, therefore, have no significant effect on Southern Company’s consolidated revenues. See Note 1 to the financial statements under “Related Party Transactions” for additional information.

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Southern Company and Subsidiary Companies Annual Report
     Operation and maintenance expenses for these other businesses increased by $12 million in 2005 as a result of $9 million of higher losses for property damage, $2 million in higher network costs at SouthernLINC Wireless, and a $11 million increase in shared services expenses, offset by the 2004 $12.5 million bad debt reserve discussed below. Operation and maintenance expenses increased $28 million in 2004 primarily due to a $3 million increase in advertising, a $5 million increase in shared services expenses, and a $12.5 million bad debt reserve related to additional federal income taxes and interest Southern Company paid on behalf of Mirant Corporation (Mirant). See FUTURE EARNINGS POTENTIAL — “Mirant Bankruptcy Matters” herein and Note 3 to the financial statements under “Mirant Matters — Mirant Bankruptcy” for additional information. Operation and maintenance expenses decreased by $23 million in 2003 primarily due to a $6 million decrease in shared services expenses and a $3 million decrease in losses for property damage at the parent company; a $4 million decrease in bad debt expense and a $3 million decrease in network costs at SouthernLINC Wireless; and a $2 million decrease in salaries in the energy-related services business.
     Depreciation and amortization expenses decreased $9 million and $7 million in 2004 and 2003, respectively. These reductions are primarily the result of $10 million of expenses associated with the repurchase of debt at Southern Holdings recorded in 2003 and a $16 million charge recorded in 2002 related to the impairment of assets under certain customer contracts for energy-related services.
     The increases in equity in losses of unconsolidated subsidiaries in 2005 and 2003 reflect the results of additional production expenses in the synthetic fuel partnerships. These partnerships also claim federal income tax credits that offset their operating losses and make the businesses profitable. These credits totaled $177 million in 2005, $146 million in 2004, and $120 million in 2003. 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” herein 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 made by the parent company.
     Total interest charges and other financing costs increased by $18 million in 2005 associated with an additional $283 million in debt outstanding and a 164 basis point increase in average interest rates on variable rate debt. Interest expense decreased $21 million in 2004 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.
Effects of Inflation
The retail operating companies and Southern Power are subject to rate regulation and party to long-term contracts, respectively, that are generally 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 Southern 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 PSCs under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Company’s wholesale business continues to focus on long-term capacity contracts, optimized by limited energy trading activities. The level of future earnings depends on numerous factors including the FERC’s market-based rate investigation, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and

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Southern Company and Subsidiary Companies Annual Report
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 Company’s primary business of selling electricity. These factors include the retail operating companies’ ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. 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.
     Southern Company system generating capacity increased 1,880 megawatts in 2005 with the completion of Plant McIntosh units 10 and 11 by Georgia Power and Savannah Electric and the acquisition by Southern Power of Plant Oleander. In general, Southern Company has constructed or acquired 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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, 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. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions.”
     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 financial

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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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.
Plant Wansley Environmental Litigation
In December 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. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. 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.
     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 financial condition if such costs are not recovered through regulated rates.
Environmental Statutes and Regulations
General
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. Applicable statutes 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 these environmental requirements

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involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, Southern Company had invested approximately $2.4 billion in capital projects to comply with these requirements, with annual totals of $423 million, $300 million, and $256 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $7.5 billion, including $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect Southern Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of Southern Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2005, the Company had spent approximately $1.6 billion in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2 and NOx emissions, maintain compliance with existing regulations, and to meet new requirements.
     Approximately $1.3 billion of these expenditures related to reducing NOx emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NOx reduction rules. In 2004, the regional NOx reduction rules were implemented for the northern two-thirds of Alabama. Although the State of Georgia was originally included in the states subject to the regional NOx rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NOx reduction rules for the State of Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of its state implementation plan.
     In addition, in 2005, Gulf Power substantially completed the terms of a 2002 agreement with the State of Florida to help ensure attainment of the ozone standard in the Pensacola, Florida area. The conditions of the agreement, which required installing additional controls on certain units and retiring three older units at a plant near Pensacola, will be fully implemented in 2006 at a cost of approximately $134.4 million, of which $4.3 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.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. Areas within Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham (Alabama), Macon (Georgia), and a 20-county area within metropolitan Atlanta. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, are required for most areas by June 2007. These state implementation plans could require further reductions in NOx emissions from power plants.
     In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment. The final outcome of this matter cannot now be determined.
     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia, and the EPA proposed

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a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at Southern Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2, NOx, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.
     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 and two others are scheduled for completion in 2008. The total estimated cost of these projects is $173 million, with $85 million remaining to be spent.

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Georgia Power is also conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.
     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.
Environmental Remediation
Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release 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.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010- 2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.
FERC Matters
Market-Based Rate Authority
Each of the retail operating companies and Southern Power has authorization from the Federal Energy Regulatory Commission (FERC) to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $16 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this

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expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $31 million, of which $11 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are subject to refund to the extent the FERC orders any changes to the IIC.
     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 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. These proceedings are still pending at the FERC. Southern Company has also received similar requests from other entities totaling approximately $14 million. Southern Company has opposed all such requests. 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.
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 “Market-Based Rate Authority” and “Generation Interconnection Agreements” above for additional

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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.
PSC Matters
Alabama Power
In October 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 increased approximately 1 percent in both January 2005 and 2006. In conjunction with the Alabama PSC’s approval of this rate mechanism, Alabama Power agreed to a moratorium until 2007 on any retail rate increase under its previously approved Rate Stabilization and Equalization Plan (Rate RSE).
     On October 4, 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates will remain unchanged if the return on equity (ROE) is between 13 percent and 14.5 percent. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006.
     See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information.
Georgia Power
In December 2004, the Georgia PSC approved the December 2004 three-year retail rate plan ending December 31, 2007 (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 in January 2005 to cover the higher costs of purchased power, operation and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability.
     Georgia Power is required to file a general rate case on or about 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. Until then, Georgia Power may not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.
     On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement. Savannah Electric will merge into Georgia Power, with Georgia Power continuing as the surviving corporation. Pending regulatory approvals, the merger is expected to occur by July 2006. See “Fuel Cost Recovery” herein and Note 3 to the financial statements under “Merger of Georgia Power and Savannah Electric” for additional information.
Mississippi Power
On December 1, 2005, Mississippi Power submitted its annual Performance Evaluation Plan (PEP) filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, Mississippi Power has requested that the Mississippi PSC approve a temporary change to allow it to exceed this cap as a result of the ongoing effects of Hurricane Katrina. Mississippi Power has requested a 5 percent, or $32 million, retail base rate increase to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.

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     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 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in expense reductions in each of those years.
Fuel Cost Recovery
The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past year, the retail operating companies have continued to experience higher than expected fuel costs for coal and natural gas. These higher fuel costs have increased the under recovered fuel costs included in the balance sheets. The retail operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. Each of the retail operating companies received approval in 2005 to increase their fuel cost recovery factors to recover existing under recovered amounts as well as projected future 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 December 2005, the Alabama PSC approved an increase that allows for the recovery of approximately $227 million in existing under recovered fuel costs over a two-year period.
     In May 2005, the Georgia PSC approved Georgia Power’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with a Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. In connection with the proposed merger, Georgia Power has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, Georgia Power and Savannah Electric will file a combined request in March 2006 to increase its fuel cost recovery rate.
     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Georgia Power and Savannah Electric generating fleet as well as the under recovered balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all Georgia Power customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the merger will be paid by the appropriate customer groups.
     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. Georgia Power and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of these matters cannot now be determined.
     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow. Based on their respective state PSC orders, a portion of the under recovered regulatory clause revenues for Alabama Power, Georgia Power, and Savannah Electric was reclassified from current assets to deferred charges and other assets in the balance sheet. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” 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 facilities 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; Gulf Power accrued an additional $6 million and $15 million in 2005 and 2004, respectively. 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, which the Florida PSC subsequently approved, allowing 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 that began in April 2005. 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 an additional $6.9 million.
     In February and December 2005, Alabama Power requested and received Alabama PSC approval of accounting orders that allowed Alabama Power to immediately return certain regulatory liabilities to the retail customers. These orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effect of these orders had no impact on net income in 2005.
     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused significant damage within Southern Company’s service area, including portions of the service areas of Alabama Power, Gulf Power, and Mississippi Power. The total incremental cost of repairing the damages to Mississippi Power’s facilities and restoring service to customers is currently estimated to be approximately $277 million net of approximately $68 million of insurance proceeds. Prior to Hurricane Katrina, Mississippi Power had a balance of approximately $3 million in its property reserve. Incremental costs incurred through December 31, 2005 were $210 million net of insurance proceeds of $68 million, of which $8 million has been received. These costs include approximately $149 million of capital additions and $133 million of operation and maintenance expenditures. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 Mississippi Power customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs or associated cost estimates. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.
     Each of the affected retail operating companies has been authorized by their respective state PSCs to defer the portion of the Hurricane Dennis and Katrina restoration costs that exceeded the balance in their storm damage reserve accounts. As of December 31, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $366 million, of which approximately $70 million and $296 million, respectively, is included in the balance sheets herein under Other Current Assets and Other Regulatory Assets. The recovery of these deferred

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costs is subject to the approval of the respective state PSCs.
     In December 2005, the Alabama PSC approved a separate rate rider to recover Alabama Power’s $51 million of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish its reserve to a target balance of $75 million over a five-year period.
     In October 2005, the Mississippi PSC issued an Interim Accounting Order requiring Mississippi Power to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. In December 2005, Mississippi Power filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. Mississippi Power is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to federal grant assistance and proposed state legislation to allow securitized financing.
     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, Gulf Power filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over 8 years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve Gulf Power’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish Gulf Power’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. Since Gulf Power will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on net income, but would increase cash flow.
     See Notes 1 and 3 to the financial statements under “Storm Damage Reserves” and “Storm Damage Cost Recovery,” respectively, for additional information on these reserves. The final outcome of these matters cannot now be determined.
Mirant Bankruptcy Matters
Mirant is an energy company with businesses that include independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership and Mirant became an independent corporate entity.
     In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant). 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.”
     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 into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these tax items and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in the Chapter 11 proceeding. Based on management’s assessment of the collectibility of this receivable, Southern Company has reserved approximately $12.5 million. If Southern Company is ultimately required to make any additional payments, Mirant’s indemnification obligation to Southern Company for these additional payments would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant, the value of which is uncertain. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy.”
     In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against

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Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability and that Southern Company caused Mirant to breach its fiduciary duties to creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the second amended complaint in February 2006. Also in February 2006, the Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy Litigation” for additional information. The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
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. Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. The IRS proposed to disallow the tax losses for one of these leases (a lease-in-lease-out, or LILO) in connection with its audit of 1996 through 2001. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS, which is subject to final approval.
     In connection with its audit of 2000 and 2001, the IRS also challenged Southern Company’s deductions related to three other international lease (sale-in-lease-out, or SILO) transactions. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company would be subject to additional interest charges of up to $34 million. The IRS has also proposed a penalty of approximately $16 million. Southern Company believes these transactions are valid leases for U.S. tax purposes, the related deductions are allowable, and the assessment of a penalty is inappropriate. Southern Company is continuing to pursue resolution of these matters with the IRS and expects to litigate the issue if necessary. Although the payment of the tax liability, exclusive of interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Through December 31, 2005, Southern Company has claimed $241 million in tax benefits related to these SILO transactions challenged by the IRS. See Note 1 to the financial statements under “Leveraged Leases” for additional information.
     Under current accounting rules, the settlement of the LILO transaction will not have a material impact on Southern Company’s financial statements; however, the Financial Accounting Standards Board (FASB) has proposed changes to the accounting for leveraged leases that are expected to become effective in 2006. If approved as proposed, these changes could require Southern Company to reflect the tax deductions that the IRS is challenging as currently payable in the balance sheet and to change the timing of income recognized for the leases, including a cumulative effect upon adoption of the change. For the LILO transaction settled with the IRS in February 2005, Southern Company estimates such cumulative effect would reduce Southern Company’s net income by up to $16 million. The impact of these proposed changes related to the SILO transactions would be dependent on the resolution of these matters with the IRS but could be significant, and potentially material, to Southern Company’s net income. The ultimate outcome of these matters cannot now be determined.
Synthetic Fuel Tax Credits
Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 45K (formerly Section 29) of the Internal Revenue Code of 1986, as amended

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(Internal Revenue Code). In accordance with Section 45K 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 result in an impairment of these investments, which total approximately $19.5 million at December 31, 2005, by Southern Company.
Construction Projects
Integrated Coal Gasification Combined Cycle
In December 2005, Southern Power and the Orlando Utilities Commission (OUC) executed definitive agreements for development of an integrated coal gasification combined cycle (IGCC) 283-megawatt project in Orlando, Florida. The definitive agreements provide that Southern Power will own at least 65 percent of the gasifier portion of the IGCC project. OUC will own the remainder of the gasifier portion and 100 percent of the combined cycle portion of the IGCC project. OUC will purchase all of the gasifier capacity from Southern Power once the plant is in commercial operation. Southern Power will construct the project and manage its operation after construction is completed. In February 2006, Southern Power signed a cooperative agreement with the DOE that provides up to $235 million in grant funding for the gasification portion of this project. The IGCC project is subject to National Environmental Policy Act review as well as state environmental review, requires certain regulatory approvals, and is expected to begin commercial operation in 2010. Southern Power’s total cost related to the IGCC project is estimated at approximately $121 million.
Plant Franklin Unit 3
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.
Nuclear
As part of a potential expansion of Plant Vogtle, Georgia Power and Southern Nuclear have notified the Nuclear Regulatory Commission (NRC) of their intent to apply for an early site permit (ESP) this year and a combined construction and operating license (COL) in 2008. In addition, a reactor design from Westinghouse Electric Company has been selected and a purchase agreement is being negotiated. Participation agreements have been reached with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. At this point, no final decision has been made regarding actual construction. The NRC’s streamlined licensing process for new nuclear units allows utilities to seek regulatory approval at various stages. These stages include design certification, which is obtained by the reactor vendor, and the ESP and COL, which are each obtained by the owner-operators of the units. An ESP indicates site approval is obtained before a company decides to build and the COL provides regulatory approval for building and operating the plant. In addition, any new Georgia Power generation must be certified by the Georgia PSC.
     Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy plans to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs, then to choose one of the applications and file it for NRC review and approval. The COL ultimately is expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.
     Southern Company is also exploring other possibilities relating to nuclear power projects, both on its own or in partnership with other utilities.
Other Matters
In accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, Southern Company recorded non-cash pre-tax pension income/(expense) of approximately $(2) million, $44 million, and $99 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for Southern Company were $118 million, $106 million, and $101 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including

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trust earnings and changes to the plans. A portion of pension 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 88 percent of Southern Company’s total earnings for 2005, 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 (Statement No. 71), 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 and accounting principles generally accepted in the United States. 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 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.

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  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 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, 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
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. Southern Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, Southern Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, Southern Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” At December 31, 2005, Southern Company recorded additional asset retirement obligations (and assets) of approximately $153 million. The adoption of FIN 47 did not have any effect on Southern Company’s income statement.
Stock Options
On January 1, 2006, Southern Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition continued to be stable at December 31, 2005. Net cash flow from operating activities totaled $2.5 billion, $2.7 billion, and $3.1 billion for 2005, 2004, and 2003, respectively. The $165 million decrease for 2005 resulted primarily from higher fuel costs at the retail operating companies, partially offset by increases in base rates and fuel recovery rates. The $376 million decrease from 2003 to 2004 also resulted primarily from higher fuel costs at the retail operating companies. Fuel costs are recoverable in future periods and are reflected in the balance sheets as under recovered regulatory clause revenues. See

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FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information.
     Significant balance sheet changes include a $0.4 billion increase in long-term debt and preferred stock for 2005 due to an increase of $1.1 billion in property, plant, and equipment. The majority of funds needed for property additions were provided from operating activities.
     At the close of 2005, the closing price of Southern Company’s common stock was $34.53 per share, compared with book value of $14.42 per share. The market-to-book value ratio was 240 percent at the end of 2005, compared with 242 percent at year-end 2004.
     Each of the retail operating companies, Southern Power, and SCS 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 external security issuances. 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 2006, 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 2006 outside of its existing stock option plan.
     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, security issuances, and term loan and short-term borrowings. Gulf Power and Mississippi Power are considering other financing options for storm recovery costs. However, the type and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by the retail operating companies is generally subject to the approval of the applicable state PSC. In addition, the issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power and Savannah Electric is generally subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission 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.
     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. 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.
     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 sources of liquidity. 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, 2005, Southern Company and its subsidiaries had approximately $202 million of cash and cash equivalents and $3.3 billion of unused credit arrangements with banks, of which $810 million expire in 2006 and $2.5 billion expire in 2007 and beyond. Approximately $228 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional two-year period, and $311 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. See Note 6

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to the financial statements under “Bank Credit Arrangements” for additional information.
Financing Activities
During 2005, Southern Company and its subsidiaries issued $1.6 billion of long-term debt and $55 million of preference stock. The security issuances were used to redeem $1.3 billion of long-term debt, to fund Southern Company’s ongoing construction program, and for general corporate purposes. In addition, Southern Company issued 10.1 million new shares of common stock through the Company’s stock plans and realized proceeds of $213 million. In a program designed primarily to offset these issuances, Southern Company also repurchased 10.1 million shares of common stock at a total cost of $352 million. The repurchase program was discontinued in early January 2006.
     Subsequent to December 31, 2005, Alabama Power issued $600 million of long-term senior notes to reduce short-term debt and for other general corporate purposes. In conjunction with these transactions, Alabama Power terminated $600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period. In addition, Southern Company redeemed $72 million in long-term debt payable to affiliated trusts following the repurchase of the underlying capital securities.
Off-Balance Sheet Financing Arrangements
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for 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
Southern 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, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $196.4 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $602.3 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Southern 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 risk management activities. At December 31, 2005, Southern Company and its subsidiaries had no material exposure under these contracts.
     Subsequent to December 31, 2005, the Company has entered into additional physical electricity purchases and sales contracts adding $9 million to the maximum potential collateral requirements at a credit rating of BBB and Baa2 and $17 million at BBB- or Baa3 and below.
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.

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     To mitigate future exposure to change in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. These swaps have a notional amount of $930 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $1.5 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.37 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 $15.4 million at January 1, 2006. 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 natural gas purchases. The retail operating companies have implemented fuel-hedging programs at the instruction of their respective state PSCs. Southern Company Gas also utilized 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
    2005   2004
    (in millions)
Contracts beginning of year
  $ 10.5     $ 15.8  
Contracts realized or settled
    (106.1 )     (58.7 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    196.1       53.4  
 
Contracts end of year
  $ 100.5     $ 10.5  
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
Source of 2005 Year-End Valuation Prices
    Total   Maturity
    Fair Value   2006   2007-2008
    (in millions)
Actively quoted
  $ 101.6     $ 67.6     $ 34.0  
External sources
    (1.1 )     (1.1 )      
Models and other
                 
 
Contracts end of year
  $ 100.5     $ 66.5     $ 34.0  
 
     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 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, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in millions)
Regulatory liabilities, net
  $ 103.4  
Other comprehensive income
    (0.3 )
Net income
    (2.6 )
 
Total fair value
  $ 100.5  
 
     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 $2.8 billion for 2006, $3.6

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
billion for 2007, and $3.1 billion for 2008. Environmental expenditures included in these amounts are $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, 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 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.
     As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also, as discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal 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 final installment is scheduled to occur in 2006.
     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, derivative obligations, preferred and preference 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)
Southern Company and Subsidiary Companies 2005 Annual Report
Contractual Obligations
                                         
            2007-   2009-   After    
    2006   2008   2010   2010   Total
    (in millions)
Long-term debt(a)
                                       
Principal
  $ 901     $ 1,966     $ 834     $     $ 3,701  
Interest
    688       1,246       1,108       9,752       12,794  
Other derivative obligations(b)
                                       
Commodity
    32                         32  
Preferred and preference stock dividends(c)
    33       65       65             163  
Operating leases
    123       205       156       259       743  
Purchase commitments(d)
                                       
Capital(e)
    2,772       6,673                   9,445  
Coal
    3,129       3,959       1,558       364       9,010  
Nuclear fuel
    63       62       34       89       248  
Natural gas(f)
    1,495       1,286       740       3,046       6,567  
Purchased power
    175       356       305       541       1,377  
Long-term service agreements
    71       175       180       1,334       1,760  
Trusts –
                                       
Nuclear decommissioning
    7       14       14       117       152  
Postretirement benefits(g)
    45       88                   133  
DOE
    9                         9  
 
Total
  $ 9,543     $ 16,095     $ 4,994     $ 15,502     $ 46,134  
 
(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, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
 
(b)   For additional information, see Notes 1 and 6 to the financial statements.
 
(c)   Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
 
(d)   Southern Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $3.5 billion, $3.3 billion, and $3.2 billion, respectively.
 
(e)   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, 2005, significant purchase commitments were outstanding in connection with the construction program.
 
(f)   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, 2005.
 
(g)   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 Southern Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company’s 2005 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 and repairs, environmental regulations and expenditures, earnings growth, dividend payout ratios, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and Georgia Power, impacts of the adoption of new accounting rules, 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, implementation of the Energy Policy Act of 2005, 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, FERC matters, IRS audits, and Mirant 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, including rate cases relating to fuel cost recovery;
 
  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 Securities and Exchange Commission.
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, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report
                         
    2005   2004   2003
    (in millions)
Operating Revenues:
                       
Retail sales
  $ 11,165     $ 9,732     $ 8,875  
Sales for resale
    1,667       1,341       1,358  
Other electric revenues
    446       392       514  
Other revenues
    276       264       271  
 
Total operating revenues
    13,554       11,729       11,018  
 
Operating Expenses:
                       
Fuel
    4,495       3,399       2,999  
Purchased power
    731       643       473  
Other operations
    2,394       2,263       2,177  
Maintenance
    1,116       1,027       937  
Depreciation and amortization
    1,176       949       1,022  
Taxes other than income taxes
    680       627       586  
 
Total operating expenses
    10,592       8,908       8,194  
 
Operating Income
    2,962       2,821       2,824  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    51       47       25  
Interest income
    36       27       36  
Equity in losses of unconsolidated subsidiaries
    (119 )     (95 )     (99 )
Leveraged lease income
    74       70       66  
Interest expense, net of amounts capitalized
    (619 )     (540 )     (527 )
Interest expense to affiliate trusts
    (128 )     (100 )      
Distributions on mandatorily redeemable preferred securities
          (27 )     (151 )
Preferred dividends of subsidiaries
    (30 )     (30 )     (21 )
Other income (expense), net
    (41 )     (59 )     (52 )
 
Total other income and (expense)
    (776 )     (707 )     (723 )
 
Earnings From Continuing Operations Before Income Taxes
    2,186       2,114       2,101  
Income taxes
    595       585       618  
 
Earnings From Continuing Operations
    1,591       1,529       1,483  
Earnings from discontinued operations, net of income taxes of $-, $2, and $(6) for 2005, 2004, and 2003, respectively
          3       (9 )
 
Consolidated Net Income
  $ 1,591     $ 1,532     $ 1,474  
 
Common Stock Data:
                       
Earnings per share from continuing operations—
                       
Basic
  $ 2.14     $ 2.07     $ 2.04  
Diluted
    2.13       2.06       2.03  
Earnings per share including discontinued operations—
                       
Basic
  $ 2.14     $ 2.07     $ 2.03  
Diluted
    2.13       2.06       2.02  
 
Average number of shares of common stock outstanding — (in millions)
                       
Basic
    744       739       727  
Diluted
    749       743       732  
 
Cash dividends paid per share of common stock
  $ 1.475     $ 1.415     $ 1.385  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report
                 
Assets   2005   2004
    (in millions)
Current Assets:
               
Cash and cash equivalents
  $ 202     $ 368  
Receivables —
               
Customer accounts receivable
    868       697  
Unbilled revenues
    304       304  
Under recovered regulatory clause revenues
    770       532  
Other accounts and notes receivable
    410       310  
Accumulated provision for uncollectible accounts
    (38 )     (33 )
Fossil fuel stock, at average cost
    398       308  
Vacation pay
    109       105  
Materials and supplies, at average cost
    671       602  
Assets from risk management activities
    125       38  
Prepaid expenses
    130       126  
Other
    256       134  
 
Total current assets
    4,205       3,491  
 
Property, Plant, and Equipment:
               
In service
    43,578       41,425  
Less accumulated depreciation
    15,727       14,947  
 
 
    27,851       26,478  
Nuclear fuel, at amortized cost
    262       218  
Construction work in progress
    1,367       1,662  
 
Total property, plant, and equipment
    29,480       28,358  
 
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    954       905  
Leveraged leases
    1,082       976  
Other
    337       366  
 
Total other property and investments
    2,373       2,247  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    937       864  
Prepaid pension costs
    1,022       986  
Unamortized debt issuance expense
    162       153  
Unamortized loss on reacquired debt
    309       323  
Deferred under recovered regulatory clause revenues
    531        
Other regulatory assets
    525       253  
Other
    333       280  
 
Total deferred charges and other assets
    3,819       2,859  
 
Total Assets
  $ 39,877     $ 36,955  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report
                 
Liabilities and Stockholders’ Equity   2005   2004
    (in millions)
Current Liabilities:
               
Securities due within one year
  $ 901     $ 983  
Notes payable
    1,258       426  
Accounts payable
    1,229       877  
Customer deposits
    220       199  
Accrued taxes —
               
Income taxes
    104       47  
Other
    319       242  
Accrued interest
    204       179  
Accrued vacation pay
    144       137  
Accrued compensation
    459       424  
Other
    402       284  
 
Total current liabilities
    5,240       3,798  
 
Long-term Debt (See accompanying statements)
    10,958       10,488  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    1,888       1,961  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    5,736       5,243  
Deferred credits related to income taxes
    311       373  
Accumulated deferred investment tax credits
    527       552  
Employee benefit obligations
    930       864  
Asset retirement obligations
    1,117       903  
Other cost of removal obligations
    1,295       1,296  
Other regulatory liabilities
    323       328  
Other
    267       310  
 
Total deferred credits and other liabilities
    10,506       9,869  
 
Total Liabilities
    28,592       26,116  
 
Preferred and Preference Stock of Subsidiaries (See accompanying statements)
    596       561  
 
Common Stockholders’ Equity (See accompanying statements)
    10,689       10,278  
 
Total Liabilities and Stockholders’ Equity
  $ 39,877     $ 36,955  
 
Commitments and Contingent Matters (See notes)
               
 
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, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report
                         
    2005   2004   2003
    (in millions)
Operating Activities:
                       
Consolidated net income
  $ 1,591     $ 1,532     $ 1,474  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
                       
Depreciation and amortization
    1,398       1,161       1,281  
Deferred income taxes and investment tax credits
    499       559       427  
Storm damage accounting order
    48              
Allowance for equity funds used during construction
    (51 )     (47 )     (25 )
Equity in losses of unconsolidated subsidiaries
    119       95       99  
Leveraged lease income
    (74 )     (70 )     (66 )
Pension, postretirement, and other employee benefits
    (6 )     (22 )     (40 )
Tax benefit of stock options
    50       31       30  
Hedge settlements
    (19 )     (10 )     (116 )
Other, net
    (22 )     37       32  
Changes in certain current assets and liabilities —
                       
Receivables
    (1,045 )     (392 )     (11 )
Fossil fuel stock
    (110 )     (8 )     (17 )
Materials and supplies
    (78 )     (31 )     (12 )
Other current assets
    (1 )     9       26  
Accounts payable
    71       29       (88 )
Accrued taxes
    28       (109 )     19  
Accrued compensation
    13       (23 )     (11 )
Other current liabilities
    119       (46 )     69  
 
Net cash provided from operating activities
    2,530       2,695       3,071  
 
Investing Activities:
                       
Property additions
    (2,370 )     (2,022 )     (1,964 )
Nuclear decommissioning trust fund purchases
    (606 )     (810 )     (1,007 )
Nuclear decommissioning trust fund sales
    596       781       978  
Investment in unconsolidated subsidiaries
    (115 )     (97 )     (94 )
Cost of removal net of salvage
    (128 )     (75 )     (80 )
Other
    (6 )     (35 )     (27 )
 
Net cash used for investing activities
    (2,629 )     (2,258 )     (2,194 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    831       (141 )     (366 )
Proceeds —
                       
Long-term debt
    1,608       1,861       3,494  
Mandatorily redeemable preferred securities
          200        
Preferred and preference stock
    55       175       125  
Common stock
    213       124       470  
Redemptions —
                       
Long-term debt
    (1,285 )     (1,246 )     (3,009 )
Mandatorily redeemable preferred securities
          (240 )     (480 )
Preferred and preference stock
    (4 )     (28 )      
Common stock repurchased
    (352 )            
Payment of common stock dividends
    (1,098 )     (1,045 )     (1,004 )
Other
    (35 )     (40 )     (69 )
 
Net cash (used for) provided from financing activities
    (67 )     (380 )     (839 )
 
Net Change in Cash and Cash Equivalents
    (166 )     57       38  
Cash and Cash Equivalents at Beginning of Year
    368       311       273  
 
Cash and Cash Equivalents at End of Year
  $ 202     $ 368     $ 311  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report
                                     
        2005   2004   2005   2004
        (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                  
 
Total first mortgage bonds
        45       105                  
 
Long-term senior notes and debt —
                                   
Maturity
  Interest Rates                                
2005
  5.49% to 5.50%           379                  
2006
  2.65% to 6.20%     674       674                  
2007
  3.50% to 7.13%     1,207       1,220                  
2008
  2.54% to 6.55%     461       462                  
2009
  4.10% to 7.00%     128       169                  
2010
  4.70%     102       102                  
2011 through 2044
  4.00% to 8.12%     5,637       4,433                  
Adjustable rates (at 1/1/06):
                                   
2005
  1.66% to 3.63%           563                  
2006
  2.11%     27       195                  
2007
  2.11% to 5.755     265       90                  
2009
  4.53% to 4.64%     440       440                  
2010
  5.41%     154                        
 
Total long-term senior notes and debt
        9,095       8,727                  
 
Other long-term debt —
                                   
Pollution control revenue bonds —
                                   
Maturity
  Interest Rates                                
Collateralized:
                                   
2006
  5.25%     12       12                  
2024
  5.50%     3       24                  
Variable rates (at 1/1/06):
                                   
2015 through 2017
  2.01% to 2.16%     90       90                  
Non-collateralized:
                                   
2012 through 2034
  2.83% to 5.45%     850       850                  
Variable rates (at 1/1/06):
                                   
2011 through 2038
  2.01% to 3.87%     1,586       1,565                  
 
Total other long-term debt
        2,541       2,541                  
 
Capitalized lease obligations
        110       115                  
 
Unamortized debt (discount), net
        (19 )     (17 )                
 
Total long-term debt (annual interest requirement — $561 million)
        11,772       11,471                  
Less amount due within one year
        814       983                  
 
Long-term debt excluding amount due within one year
        10,958       10,488       45.4 %     45.1 %
 

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report
                                 
    2005   2004   2005   2004
    (in millions)   (percent of total)
Long-term Debt Payable to Affiliated Trusts:
                               
Maturity                      Interest Rates
                               
2027 through 2044       4.75% to 8.19%
                               
(annual interest requirement — $128 million)
    1,960       1,961                  
Less amount due within one year
    72                        
 
Total long-term debt payable to affiliated trusts excluding amount due within one year
    1,888       1,961       7.8       8.4  
 
Preferred and Preference Stock of Subsidiaries:
                               
Cumulative preferred stock
                               
$100 par or stated value — 4.20% to 5.44%
                               
Authorized — 20 million shares
                               
Outstanding — 1 million shares
    96       100                  
$1 par value — 4.95% to 5.83%
                               
Authorized — 28 million shares
                               
Outstanding — 12 million shares: $25 stated value
    294       294                  
Outstanding — 1,250 shares: $100,000 stated value
    123       123                  
Non-cumulative preferred stock
                               
$25 par or stated value — 6.00%
                               
Authorized — 4 million shares
                               
Outstanding — 2 million shares
    44       44                  
Non-cumulative preference stock
                               
$100 par or stated value — 6.00%
                               
Authorized — 10 million shares
                               
Outstanding — 1 million shares
    54                        
 
Total preferred and preference stock of subsidiaries
                               
(annual dividend requirement — $33 million)
    611       561                  
Less amount due within one year
    15                        
 
Preferred and preference stock of subsidiaries excluding amount due within one year
    596       561       2.5       2.4  
 
Common Stockholders’ Equity:
                               
Common stock, par value $5 per share —
    3,759       3,709                  
Authorized — 1 billion shares
                               
Issued — 2005: 752 million shares
                               
— 2004: 742 million shares
                               
Treasury — 2005: 10.4 million shares
                               
— 2004: 0.2 million shares
                               
Paid-in capital
    1,085       869                  
Treasury, at cost
    (359 )     (6 )                
Retained earnings
    6,332       5,839                  
Accumulated other comprehensive income (loss)
    (128 )     (133 )                
 
Total common stockholders’ equity
    10,689       10,278       44.3       44.1  
 
Total Capitalization
  $ 24,131     $ 23,288       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, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report
                                                         
                                    Accumulated    
                                    Other Comprehensive    
    Common Stock           Income (Loss)    
    Par   Paid-In           Retained   Continuing   Discontinued    
    Value   Capital   Treasury   Earnings   Operations   Operations   Total
    (in millions)
Balance at December 31, 2002
  $ 3,583     $ 338     $ (3 )   $ 4,874     $ (95 )   $ 13     $ 8,710  
Net income
                      1,474                   1,474  
Other comprehensive income (loss)
                            (20 )     (11 )     (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       (115 )     2       9,648  
Net income
                      1,532                   1,532  
Other comprehensive income (loss)
                            (16 )     (4 )     (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       (131 )     (2 )     10,278  
Net income
                      1,591                   1,591  
Other comprehensive income (loss)
                            3       2       5  
Stock issued
    50       216                               266  
Stock repurchased, at cost
                (352 )                       (352 )
Cash dividends
                      (1,098 )                 (1,098 )
Other
                (1 )                       (1 )
 
Balance at December 31, 2005
  $ 3,759     $ 1,085     $ (359 )   $ 6,332     $ (128 )   $     $ 10,689  
 
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report
    2005   2004   2003
    (in millions)
Consolidated Net Income
  $ 1,591     $ 1,532     $ 1,474  
 
Other comprehensive income (loss) — continuing operations:
                       
Change in additional minimum pension liability, net of tax of $(6), $(11), and $(11), respectively
    (11 )     (20 )     (17 )
Change in fair value of marketable securities, net of tax of $(2) and $4, respectively
    (4 )     6        
Changes in fair value of qualifying hedges, net of tax of $7, $(11), and $(12), respectively
    12       (16 )     (20 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $4, $8, and $9, respectively
    6       14       17  
 
Total other comprehensive income (loss) — continuing operations
    3       (16 )     (20 )
 
Other comprehensive income (loss) — discontinued operations:
                       
Changes in fair value of qualifying hedges, net of tax of $4, $(1), and $10, respectively
    6       (2 )     3  
Less: Reclassification adjustment for amounts included in net income, net of tax of $(3), $(1), and $(8), respectively
    (4 )     (2 )     (14 )
 
Total other comprehensive income (loss) — discontinued operations
    2       (4 )     (11 )
 
Consolidated Comprehensive Income
  $ 1,596     $ 1,512     $ 1,443  
 
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2005 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company (the 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 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). 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 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.
     On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary, including natural gas inventory, accounts receivable, and customer list, to Gas South, LLC, an affiliate of Cobb Electric Membership Corporation. As a result of the sale, Southern Company’s financial statements and related information reflect Southern Company Gas as discontinued operations. For additional information, see Note 3 under “Southern Company Gas Sale.”
     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 was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and the Company and its subsidiaries were subject to the regulatory provisions of the PUHCA. The retail operating companies, Southern Power, and certain of their subsidiaries 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 2005, 2004, and 2003 were $507 million, $409 million, and $312 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 $83 million, $82 million, and $65 million in 2005, 2004, and 2003, 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 $40 million, $24 million, and $20 million in 2005, 2004, and 2003, respectively.

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
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:
                         
    2005   2004   Note
    (in millions)
Deferred income tax charges
  $ 937     $ 865       (a )
Asset retirement obligations — asset.
    81       7       (a )
Asset retirement obligations — liab.
    (139 )     (180 )     (a )
Other cost of removal obligations
    (1,295 )     (1,296 )     (a )
Deferred income tax credits
    (313 )     (374 )     (a )
Loss on reacquired debt
    309       323       (b )
Vacation pay
    109       105       (c )
Building lease
    52       53       (d )
Generating plant outage costs — asset
    54       49       (d )
Storm damage — asset
    366       97       (d )
Fuel hedging
    (116 )     (27 )     (d )
Other assets
    139       115       (d )
Environmental remediation — asset
    58       59       (d )
Environmental remediation — liab.
    (36 )     (47 )     (d )
Deferred purchased power
    (52 )     (19 )     (d )
Other liabilities
    (32 )     (26 )     (d )
Plant Daniel capacity
    (19 )     (44 )     (e )
 
Total
  $ 103     $ (340 )        
 
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)   Recorded and recovered or amortized as approved by the appropriate state PSCs.
 
(e)   Amortized over four-year period ending in 2007.
     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 to be reflected in rates.
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 these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
     Retail fuel costs recovery mechanisms vary by each retail operating company, but in general, the process requires periodic filings with the appropriate state PSC. Alabama Power continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. The Georgia PSC requires that such amounts be reviewed semi-annually. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power is required to file for a temporary fuel rate change. If the over or under recovery exceeds 10 percent of the projected fuel costs for the period, Gulf Power is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary. Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually. See “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” in Note 3 for additional information.
     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

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
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 2005, $134 million in 2004, and $138 million in 2003.
Nuclear Fuel Disposal Costs
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 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 Plants Hatch and Farley, on-site dry storage facilities are operational and can be expanded to accommodate spent fuel through the life of each 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 has been paid over a 15-year period; the final installment is scheduled to occur in 2006. 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, 2005 under this law to be approximately $5 million and $4 million.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.
     Southern Company’s property, plant, and equipment consisted of the following at December 31 (in millions):
                 
    2005   2004
 
Generation
  $ 22,490     $ 21,262  
Transmission
    6,031       5,770  
Distribution
    11,894       11,368  
General
    2,393       2,268  
Plant acquisition adjustment
    41       42  
 
Utility plant in service
    42,849       40,710  
 
IT equipment and software
    211       214  
Communications equipment
    431       404  
Other
    87       97  
 
Other plant in service
    729       715  
 
Total plant in service
  $ 43,578     $ 41,425  
 
     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 a Georgia PSC order, Georgia Power also 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.
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 utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2005, 3.0 percent in 2004, and 3.1 percent in 2003. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the retail operating companies. Accumulated depreciation for utility plant in service totaled $15.3 billion and $14.6 billion at December 31, 2005 and

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
2004, respectively. 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 and $14 million in 2004 and 2003, respectively. See Note 3 under “Georgia Power Retail Regulatory Matters” 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 related regulatory liability pursuant to the Mississippi PSC’s order 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.
     Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from 3 to 25 years. Accumulated depreciation for other plant in service totaled $378 million and $345 million at December 31, 2005 and 2004, respectively.
Asset Retirement Obligations
and Other Costs of Removal
Effective January 1, 2003, Southern Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which 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. In addition, effective December 31, 2005, Southern Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in 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 or Interpretation No. 47.
     The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, Plants Farley, Hatch, and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2005 was $954 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, Southern Company also recorded additional asset retirement obligations (and assets) of approximately $153 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. 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 assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
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 Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, 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:
                 
    2005   2004
    (in millions)
Balance beginning of year
  $ 903     $ 845  
Liabilities incurred
    155        
Liabilities settled
    (2 )     (3 )
Accretion
    61       57  
Cash flow revisions
          4  
 
Balance end of year
  $ 1,117     $ 903  
 
     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $1.0 billion.
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. Use of the funds is restricted to nuclear decommissioning activities and the funds 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). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:
                         
    Unrealized   Unrealized   Fair
2005   Gains   Losses   Value
            (in millions)        
Equity
  $ 155.6     $ (14.0 )   $ 600.8  
Debt
    4.1       (2.4 )     241.4  
Other
    17.0             111.4  
Total
  $ 176.7     $ (16.4 )   $ 953.6  
 
                         
    Unrealized   Unrealized   Fair
2004   Gains   Losses   Value
            (in millions)        
Equity
  $ 140.0     $ (8.3 )   $ 566.3  
Debt
    8.5       (0.7 )     233.5  
Other
    13.6       (0.2 )     105.0  
Total
  $ 162.1     $ (9.2 )   $ 904.8  
 
     The contractual maturities of debt securities at December 31, 2005 are as follows: $17.3 million in 2006; $90.1 million in 2007-2010; $59.5 million in 2011-2015; and $65.5 million thereafter.
     Sales of the securities held in the trust funds resulted in proceeds of $596.3 million, $781.3 million, and $978.1 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $22.5 million, $21.6 million, and $19.6 million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and did not require the recognition of any impairment related to the underlying investments.
     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 designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2005, the accumulated provisions for decommissioning were as follows:
                         
    Plant   Plant   Plant
    Farley   Hatch   Vogtle
            (in millions)        
External trust funds, at fair value
  $ 467     $ 313     $ 174  
Internal reserves
    28             1  
 
Total
  $ 495     $ 313     $ 175  
 

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Southern Company and Subsidiary Companies 2005 Annual Report
     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, which were performed in 2003, for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle were as follows:
                         
    Plant   Plant   Plant
    Farley   Hatch   Vogtle
 
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.
     For ratemaking purposes, Alabama Power’s decommissioning costs are based on the site study and Georgia Power’s decommissioning costs are 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. Amounts expensed in 2005, 2004, and 2003 totaled $7 million, $27 million, and $27 million, 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 licenses for Plants Farley and 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.
     In May 2005, the NRC granted Alabama Power a similar 20-year extension of the operating license for both units at Plant Farley. As a result of the Farley license extension, amounts previously contributed to the external trust fund are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved Alabama Power’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust fund. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of trust funds to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with NRC and other applicable requirements. The approved suspension would not affect the transfer of internal reserves (less than $1 million annually) to the external trust over the remaining life of the licenses.
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 $661 million, $551 million, and $603 million in 2005, 2004, and 2003, respectively, net of amounts capitalized of $21 million, $36 million, and $49 million, respectively.
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

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Southern Company and Subsidiary Companies 2005 Annual Report
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.
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 facilities and to generation facilities and other property. In accordance with their respective state PSC orders, the retail operating companies accrued $15 million in 2005 that is recoverable through base rates. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2005, 2004, and 2003, such additional accruals totaled $6 million, $25 million, and $8 million, respectively. See Note 3 under “Storm Damage Recovery” for additional information regarding the depletion of these reserves following Hurricanes Ivan, Dennis, and Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which may be approved by the respective state PSCs to replenish these reserves.
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 continues to recover environmental costs through its base rates. Beginning in 2005, such rates include an annual 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 Georgia PSC ratemaking provisions, $22 million had previously been deferred in a regulatory liability account for use in meeting future environmental remediation costs of Georgia Power and is being amortized over a three-year period that began in January 2005.
     In September 2004, Gulf Power increased its liability for the estimated costs of environmental remediation projects by approximately $47 million. This increase related 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 net income as a result of these revised estimates.
     For Southern Company, the environmental remediation liabilities balances as of December 31, 2005 and 2004 totaled $62 million and $63 million, respectively.
Leveraged Leases
Southern Company has several leveraged lease agreements, ranging up to 45 years, which 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 domestic leveraged leases consists of the following at December 31:
                 
    2005   2004
    (in millions)
Net rentals receivable
  $ 509     $ 457  
Unearned income
    (280 )     (283 )
 
Investment in leveraged leases
    229       174  
Deferred taxes arising from leveraged leases
    (59 )     (32 )
 
Net investment in leveraged leases
  $ 170     $ 142  
 
     A summary of the components of income from domestic leveraged leases is as follows:
                         
    2005   2004   2003
            (in millions)        
Pretax leveraged lease income
  $ 23     $ 17     $ 11  
Income tax expense
    (11 )     (8 )     (4 )
 
Net leveraged lease income
  $ 12     $ 9     $ 7  
 

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     Southern Company’s net investment in international leveraged leases consists of the following at December 31:
                 
    2005   2004
    (in millions)
Net rentals receivable
  $ 1,298     $ 1,298  
Unearned income
    (445 )     (496 )
 
Investment in leveraged leases
    853       802  
Deferred taxes arising from leveraged leases
    (351 )     (360 )
 
Net investment in leveraged leases
  $ 502     $ 442  
 
     A summary of the components of income from international leveraged leases is as follows:
                         
    2005   2004   2003
            (in millions)        
Pretax leveraged lease income
  $ 51     $ 53     $ 55  
Income tax expense
    (18 )     (19 )     (19 )
 
Net leveraged lease income
  $ 33     $ 34     $ 36  
 
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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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.
     For pro forma purposes, Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on earnings from continuing operations is as follows:
                         
    As             Options   Pro     
    Reported   Impact   Forma
 
2005
                       
Net income (in millions)
  $ 1,591     $ (17 )   $ 1,574  
Earnings per share (dollars):
                       
Basic
  $ 2.14     $ (0.02 )   $ 2.12  
Diluted
  $ 2.13     $ (0.03 )   $ 2.10  
2004
                       
Net income (in millions)
  $ 1,529     $ (16 )   $ 1,513  
Earnings per share (dollars):
                       
Basic
  $ 2.07     $ (0.02 )   $ 2.05  
Diluted
  $ 2.06     $ (0.02 )   $ 2.04  
2003
                       
Net income (in millions)
  $ 1,483     $ (17 )   $ 1,466  
Earnings per share (dollars):
                       
Basic
  $ 2.04     $ (0.02 )   $ 2.02  
Diluted
  $ 2.03     $ (0.03 )   $ 2.00  
     The estimated fair values of stock options granted in 2005, 2004, and 2003 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:
                         
    2005   2004   2003
 
Interest rate
    3.9 %     3.1 %     2.7 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.9 %     19.6 %     23.6 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
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.

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Southern Company and Subsidiary Companies 2005 Annual Report
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 or are recoverable through the retail operating companies’ fuel hedging programs. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges 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:
               
2005
  $ 13,623     $ 13,633  
2004
    13,317       13,560  
     The fair values were based on either closing market price or closing price of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, 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
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Southern Company has established certain wholly-owned trusts established to issue preferred securities. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information. However, 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 in the balance sheets.
     In addition, Southern Company holds an 85 percent limited partnership investment in an energy/technology venture capital fund that is consolidated in the financial statements. 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, 2005, Southern Company’s investment totaled $25.6 million.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees. The retail operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately $45 million.
     The measurement date for plan assets and obligations is September 30 for each year presented.
Pension Plans
The total accumulated benefit obligation for the pension plans was $5.2 billion in 2005 and $4.6 billion

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in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
    Projected
    Benefit Obligations
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 5,075     $ 4,573  
Service cost
    138       128  
Interest cost
    286       270  
Benefits paid
    (214 )     (207 )
Plan amendments
    32       6  
Actuarial (gain) loss
    240       305  
 
Balance at end of year
  $ 5,557     $ 5,075  
 
                 
    Plan Assets
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 5,476     $ 5,159  
Actual return on plan assets
    866       501  
Employer contributions
    19       23  
Benefits paid
    (214 )     (207 )
 
Balance at end of year
  $ 6,147     $ 5,476  
 
     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $5.2 billion and $0.4 billion, respectively. All plan assets are related to the qualified plan.
     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   2005   2004
 
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
    2005   2004
 
    (in millions)
Funded status
  $ 590     $ 401  
Unrecognized transition amount
    (6 )     (14 )
Unrecognized prior service cost
    293       292  
Unrecognized net (gain) loss
    3       185  
 
Prepaid pension asset, net
  $ 880     $ 864  
 
     The prepaid pension asset, net is reflected in the balance sheets in the following line items:
    2005   2004
 
    (in millions)
Prepaid pension asset
  $ 1,022     $ 986  
Employee benefit obligations
    (310 )     (280 )
Other property and investments
    43       50  
Accumulated other comprehensive income
    125       108  
 
Prepaid pension asset, net
  $ 880     $ 864  
 
     Components of the pension plans’ net periodic cost were as follows:
                         
    2005   2004   2003
 
    (in millions)
Service cost
  $ 138     $ 128     $ 115  
Interest cost
    286       269       261  
Expected return on plan assets
    (456 )     (452 )     (450 )
Recognized net gain
    10       (7 )     (42 )
Net amortization
    24       18       17  
 
Net pension cost (income)
  $ 2     $ (44 )   $ (99 )
 
     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, 2005, estimated benefit payments were as follows:
    (in millions)
2006
  $ 222  
2007
    230  
2008
    238  
2009
    248  
2010
    262  
2011 to 2015
    1,596  
 
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

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    Accumulated
    Benefit Obligations
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 1,712     $ 1,655  
Service cost
    28       27  
Interest cost
    96       93  
Benefits paid
    (78 )     (68 )
Actuarial (gain) loss
    68       72  
Plan amendments
          (67 )
 
Balance at end of year
  $ 1,826     $ 1,712  
 
                 
    Plan Assets
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 592     $ 522  
Actual return on plan assets
    78       64  
Employer contributions
    92       74  
Benefits paid
    (78 )     (68 )
 
Balance at end of year
  $ 684     $ 592  
 
     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   2005   2004
 
Domestic equity
    44 %     46 %     43 %
International equity
    17       18       18  
Fixed income
    29       29       32  
Real estate
    6       5       4  
Private equity
    4       2       3  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
    2005   2004
 
    (in millions)
Funded status
  $ (1,142 )   $ (1,120 )
Unrecognized transition obligation
    114       129  
Unrecognized prior service cost
    121       130  
Unrecognized net loss (gain)
    428       408  
Fourth quarter contributions
    40       30  
 
Accrued liability recognized in the balance sheets
  $ (439 )   $ (423 )
 
     Components of the postretirement plans’ net periodic cost were as follows:
    2005   2004   2003
 
    (in millions)
Service cost
  $ 28     $ 28     $ 25  
Interest cost
    97       93       93  
Expected return on plan assets
    (45 )     (50 )     (47 )
Net amortization
    38       35       30  
 
Net postretirement cost
  $ 118     $ 106     $ 101  
 
     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 and for the year ended December 31, 2005 by approximately $10.6 million and $26 million, respectively, and is expected to have a similar impact on future expenses.
     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)
2006
  $ 86     $ (7 )   $ 79  
2007
    92       (9 )     83  
2008
    100       (10 )     90  
2009
    110       (11 )     99  
2010
    119       (12 )     107  
2011 to 2015
    668       (88 )     580  
 
Actuarial Assumptions
     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:

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Southern Company and Subsidiary Companies 2005 Annual Report
                         
    2005   2004   2003
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00       3.50       3.75  
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014 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, 2005 as follows:
                 
    1 Percent   1 Percent
    Increase   Decrease
 
    (in millions)
Benefit obligation
  $ 149     $ 132  
Service and interest costs
    10       9  
 
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 2005, 2004, and 2003 were $58 million, $56 million, and $55 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 such as opacity and other air quality standards, 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 pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, 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 Matters
Mirant Corporation (Mirant) is an energy company with businesses that include independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
Mirant Bankruptcy
In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization on December 9, 2005, and Mirant announced that this plan became effective on January 3, 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).
     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 has reserved approximately $12.5 million.

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     Under the terms of the separation agreements entered into 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 sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant, the value of which is uncertain. The final outcome of this matter cannot now be determined.
Mirant Bankruptcy Litigation
In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends include without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80 percent interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer Mirant asserts is valued at $248 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company caused Mirant to breach its fiduciary duties to creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the second amended complaint in February 2006.
     On December 29, 2005, the Bankruptcy Court entered an order transferring this proceeding, along with certain other actions, to a special purpose subsidiary of Reorganized Mirant. Under the order, Reorganized Mirant is obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits will be distributed to and shared equally by the unsecured creditors and the original equity holders.
     On January 10, 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court, and on February 15, 2006 granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. However, the final outcome of this matter 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

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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.
     During Mirant’s Chapter 11 proceeding, the securities litigation was stayed, with the exception of limited discovery. Since Mirant’s plan of reorganization has become effective, the stay has been lifted, and activity in this case is expected to resume.
     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 this matter cannot now be determined.
Southern Company Employee Savings Plan Litigation
In June 2004, an employee of a Southern Company subsidiary filed a complaint, which was amended in December 2004 and November 2005 in the U.S. District Court for the Northern District of Georgia on behalf of a purported class of 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 asserts claims under ERISA against 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 putative class period. 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 purported fiduciary duties by, among other things, failing to adequately determine whether Mirant stock was appropriate to hold in the Plan and 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 business conditions. The plaintiff 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 monetary damages.
     On October 4, 2005, the court dismissed the plaintiff’s claims for certain types of equitable relief, but allowed the remainder of the ERISA claims to proceed. The defendants filed answers to the second amended complaint in January 2006, and filed motions for summary judgment and to stay discovery in February 2006. The ultimate outcome of this matter cannot now be determined.
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against 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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, 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. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues

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associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
     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 financial condition if such costs are not recovered through regulated rates.
Plant Wansley Environmental Litigation
In December 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. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. 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.
     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 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, 2005, 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 natural resource damages at the site are anticipated. Georgia Power has also recognized $36 million in cumulative expenses through December 31, 2005 for the assessment and anticipated cleanup of other sites on the Georgia Hazardous Sites Inventory.
     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 activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements.
FERC Matters
Market-Based Rate Authority
Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate

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transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $16 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $31 million, of which $11 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.
     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 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. These proceedings are still pending at the FERC. Southern Company has also received similar requests from

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other entities totaling approximately $14 million. Southern Company has opposed all such requests. 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.
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 and amended to add four more plaintiffs. The lawsuit also raised claims on behalf of a purported class. The plaintiffs sought compensatory and punitive damages in an unspecified amount, as well as injunctive relief.
     Following various court decisions in favor of the defendants and subsequent appeals by the plaintiffs, on July 13, 2005, the plaintiffs filed a petition for writ of certiorari to the U.S. Supreme Court. On October 17, 2005, the petition was denied. This matter is now concluded.
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.
     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 are the subject of this litigation. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against Gulf Power on their respective motions for partial summary judgment. In that same order, the trial court also denied Gulf Power’s motion to dismiss certain claims. The court’s ruling allowed for an immediate appeal to the Florida First District Court of Appeal, which Gulf Power filed on December 20, 2005. If the appeal is not successful, damages will be decided at a future trial.
     In January 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. 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. Georgia Power appealed this ruling to the Georgia Court of Appeals. The Georgia Court of Appeals reversed, in part, the court’s order and remanded the case to the trial court for the determination of further issues. After the Court of Appeals’ decision, the plaintiffs filed a motion for reconsideration, which was denied, and a petition for certiorari to the Georgia Supreme Court, which is currently pending. 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.
     To date, Mississippi Power has entered into agreements with plaintiffs in approximately 90 percent of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Mississippi Power’s financial statements.
     In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power,

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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. In January 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
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. Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. The IRS proposed to disallow the tax losses for one of these leases (a lease-in-lease-out, or LILO) in connection with its audit of 1996 through 2001. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS which is subject to final approval. Under current accounting rules, the settlement of this transaction will have no material impact on Southern Company’s financial statements
     In connection with its audit of 2000 and 2001, the IRS also challenged Southern Company’s deductions related to three other international lease (sale-in-lease-out, or SILO) transactions. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company would be subject to additional interest charges of up to $34 million. The IRS has also proposed a penalty of approximately $16 million. Southern Company believes these transactions are valid leases for U.S. tax purposes, the related deductions are allowable, and the assessment of a penalty is inappropriate. Southern Company is continuing to pursue resolution of these matters with the IRS and expects to litigate the issue if necessary. Although the payment of the tax liability, exclusive of interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Through December 31, 2005, Southern Company has claimed $241 million in tax benefits related to these SILO transactions challenged by the IRS. See Note 1 under “Leveraged Leases” for additional information.
Alabama Power Retail Regulatory Matters
Alabama Power operates under a Rate Stabilization and Equalization plan (Rate RSE) approved by the Alabama PSC. Rate RSE provides for periodic annual adjustments based upon Alabama Power’s earned return on end-of-period retail common equity; however, in October 2005, Alabama Power and the Alabama PSC agreed to a moratorium on any rate increase under Rate RSE until January 2007. In October 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates will remain unchanged if the return on equity (ROE) is between 13 percent and 14.5 percent. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006. The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
     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).
     To recover certificated purchased power costs under Rate CNP, increases of 2.6 percent or $79 million annually and 0.8 percent or $25 million annually were effective July 2003 and June 2004,

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respectively. In April 2005, an annual true-up adjustment to Rate CNP decreased 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. 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 increased approximately 1 percent in both January 2005 and 2006.
     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 December 2005, the Alabama PSC approved an increase that allows for the recovery of approximately $227 million in existing under recovered fuel costs over a two-year period. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet.
Georgia Power Retail Regulatory Matters
In December 2004, the Georgia PSC approved a three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan) for Georgia Power. Under the terms of the 2004 Retail Rate Plan, Georgia Power’s earnings are 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. In 2005, Georgia Power recorded $5.3 million in revenue subject to refund related to earnings in excess of a 12.25 percent retail ROE.
     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. Until then, Georgia Power may not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent.
     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 May 17, 2005, the Georgia PSC approved Georgia Power’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet.
     Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power will be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with a Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. In connection with the proposed merger, Georgia Power has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, Georgia Power and Savannah Electric will file a combined request in March 2006 to increase its fuel cost recovery rate.
     The case will seek approval of a fuel cost

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recovery rate based upon future fuel cost projections for the combined Georgia Power and Savannah Electric generating fleet as well as the under recovered balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all Georgia Power customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the merger will be paid by the appropriate customer groups. For additional information regarding the pending merger, see “Merger of Georgia Power and Savannah Electric” below.
     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. Georgia Power and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of these matters cannot now be determined.
Storm Damage Cost Recovery
Each retail operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution facilities and the cost of uninsured damages to its generation facilities and other property. Following Hurricanes Ivan, Dennis, and Katrina in September 2004, July 2005, and August 2005, respectively, each of the affected retail operating companies has been authorized by its respective state PSC to defer the portion of the storm restoration costs incurred that exceeded the balance in its storm damage reserve account. As of December 31, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $366 million, of which approximately $70 million and $296 million, respectively, is included in the condensed balance sheets herein under Other Current Assets and Other Regulatory Assets. Approximately $81 million of the deficit balances are being recovered through separate surcharges or rate riders approved by the Florida and Alabama PSCs, as discussed further below. The recovery of the remaining deferred costs is subject to the approval of the respective state PSC.
     Hurricane Ivan caused significant damage to the service areas of both Gulf Power and Alabama Power. In February and December 2005, Alabama Power requested and received Alabama PSC approval of accounting orders that allowed Alabama Power to immediately return certain regulatory liabilities to the retail customers. The orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effect of these orders had no impact on net income in 2005. In March 2005, the Florida PSC approved a Stipulation and Settlement among Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group. The agreement allows Gulf Power to recover approximately $51.7 million in storm damage costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. Gulf Power also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.
     Hurricanes Dennis and Katrina caused significant damage within Southern Company’s service area, including portions of the service areas of Alabama Power and Gulf Power and all of Mississippi Power’s service area. Hurricane Dennis and Katrina restoration costs are currently estimated to total approximately $506 million, of which approximately $287 million relates to operation and maintenance expenditures. Approximately $60 million of these costs is expected to be covered through external insurance. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 Mississippi Power customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs or associated cost estimates. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.
     In December 2005, the Alabama PSC approved Alabama Power’s request for a separate rate rider to recover its $51 million of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish the reserve to a target balance of $75 million over a five-year period.
     Prior to Hurricane Katrina, Mississippi Power had a balance of approximately $3 million in its property reserve. In October 2005, the Mississippi PSC issued an Interim Accounting Order requiring Mississippi Power to recognize a regulatory asset in an amount

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equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. Through December 31, 2005, these incremental costs totaled $210 million, net of insurance proceeds of $68 million. These costs include approximately $133 million of operation and maintenance expenditures and approximately $49 million of capital additions, of which approximately $100 million are reflected as investing activities for purposes of the statement of cash flows. In December 2005, Mississippi Power filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. Mississippi Power is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to federal grant assistance and proposed state legislation to allow securitized financing. Also in December 2005, Mississippi Power submitted its annual Performance Evaluation Plan (PEP) filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, Mississippi Power has requested that the Mississippi PSC approve a temporary change to allow them to exceed this cap as a result of the ongoing effects of Hurricane Katrina. Mississippi Power has requested a 5 percent or $32 million retail base rate increase to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.
     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, Gulf Power filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over 8 years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve Gulf Power’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish Gulf Power’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since Gulf Power will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on net income, but would increase cash flow.
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, 2005, Southern Power’s investment in Unit 3 of Plant Franklin was $172 million. The final outcome of this matter cannot now be determined.
Southern Company Gas Sale
On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary, including natural gas inventory, accounts receivable, and customer list, to Gas South, LLC, an affiliate of Cobb Electric Membership Corporation. Southern Company Gas’ sale of such assets was pursuant to a Purchase and Sale Agreement dated November 18, 2005 between Southern Company Gas and Gas South, for an aggregate purchase price of approximately $127 million, subject to certain adjustments. This sale will have no material impact on Southern Company’s net income for the quarter ending March 31, 2006. As a result of the sale, Southern Company’s financial statements and related information reflect Southern Company Gas as discontinued operations.
Merger of Georgia Power and Savannah Electric
On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement, under which Savannah Electric will merge into Georgia Power, with Georgia Power continuing as the surviving corporation. At the effective date of the merger, each share of Georgia Power common stock will remain issued and outstanding; the issued and outstanding shares of Savannah Electric common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of Georgia Power common stock; and each share of Savannah Electric preferred stock issued and outstanding immediately prior to the merger will be converted into the right to receive one share of a new series of Georgia Power Class A Preferred Stock. The merger must be approved by the preferred shareholders of Savannah Electric, and is subject to the receipt of regulatory approvals from the FERC, Georgia PSC, and Federal Communications Commission. Pending regulatory approvals, the merger is expected to occur by July

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2006. The merger is not expected to have any material impact on Southern Company’s financial statements.
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, 2005, 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 %   $ 3,311     $ 1,809  
Plant Hatch (nuclear)
    50.1       935       492  
Plant Miller (coal) Units 1 and 2
    91.8       940       374  
Plant Scherer (coal) Units 1 and 2
    8.4       115       56  
Plant Wansley (coal)
    53.5       395       172  
Rocky Mountain (pumped storage)
    25.4       169       92  
Intercession City (combustion turbine)
    33.3       12       2  
Plant Stanton (combined cycle) Unit A
    65.0       156       10  
     At December 31, 2005, the portion of total construction work in progress related to Plants Miller, Scherer, and Wansley was $4.4 million, $0.5 million, and $8.3 million, respectively, primarily for environmental projects.
     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 combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.
     Mirant was included in the consolidated federal tax return through April 2, 2001. 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 sought reimbursement as an unsecured creditor. For additional information, see Note 3 under “Mirant Matters — Mirant Bankruptcy.”
     At December 31, 2005, the tax-related regulatory assets and liabilities were $937 million and $313 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.

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     Details of income tax provisions are as follows:
                         
    2005   2004   2003
    (in millions)
Total provision for income taxes:
                       
Federal —
                       
Current
  $ 61     $ 14     $ 141  
Deferred
    419       482       393  
 
 
    480       496       534  
 
State —
                       
Current
    35       15       44  
Deferred
    80       76       34  
 
 
    115       91       78  
 
Total
  $ 595     $ 587     $ 612  
 
     Net cash payments for income taxes in 2005, 2004, and 2003 were $100 million, $78 million, and $189 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:
                 
    2005   2004
    (in millions)
Deferred tax liabilities:
               
Accelerated depreciation
  $ 4,613     $ 4,290  
Property basis differences
    1,008       1,009  
Leveraged lease basis differences
    519       447  
Employee benefit obligations
    333       307  
Under recovered fuel clause
    528       210  
Premium on reacquired debt
    126       132  
Storm reserve
    68       47  
Other
    155       133  
 
Total
    7,350       6,575  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    263       243  
State effect of federal deferred taxes
    88       111  
Employee benefit obligations
    210       177  
Other property basis differences
    148       157  
Deferred costs
    126       105  
Unbilled revenue
    58       61  
Other comprehensive losses
    96       94  
Alternative minimum tax carryforward
    202       106  
Other
    260       233  
 
Total
    1,451       1,287  
 
Total deferred tax liabilities, net
    5,899       5,288  
Portion included in prepaid expenses (accrued income taxes), net
    (180 )     (57 )
Deferred state tax assets
    17       12  
 
Accumulated deferred income taxes in the balance sheets
  $ 5,736     $ 5,243  
 
     The alternative minimum tax credits do not expire.
     At December 31, 2005, 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 2006 and 2021. During 2005, Southern Company utilized $11 million in available net operating losses, which resulted in a $0.7 million state income tax benefit. 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 $25 million in 2005, $27 million in 2004, and $29 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.
     The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred dividends of subsidiaries, as a result of the following:
                         
    2005   2004   2003
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    3.4       2.8       2.4  
Synthetic fuel tax credits
    (8.0 )     (8.5 )     (5.7 )
Employee stock plans dividend deduction
    (1.5 )     (1.5 )     (1.5 )
Non-deductible book depreciation
    1.1       1.1       1.1  
Difference in prior years’ deferred and current tax rate
    (1.8 )     (0.7 )     (0.7 )
Other
    (1.4 )     (0.9 )     (1.5 )
 
Effective income tax rate
    26.8 %     27.3 %     29.1 %
 
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
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subordinated notes totaling $2.0 billion, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trusts (including Securities Due Within One Year). 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, 2005, preferred securities of $1.9 billion were outstanding. Southern Company guarantees $574 million of notes related to these securities issued on its behalf. Subsequent to year-end, this amount has been reduced to $502 million through the redemption of outstanding securities. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31 is as follows:
                 
    2005     2004  
    (in millions)  
Capitalized leases
  $ 13     $ 12  
First mortgage bonds
    45        
Pollution control bonds
    12        
Senior notes
    697       675  
Long-term debt payable to affiliated trusts
    72        
Other long-term debt
    47       296  
Preferred stock
    15        
 
Total
  $ 901     $ 983  
 
     Debt and preferred stock redemptions, and/or serial maturities through 2010 applicable to total long-term debt are as follows: $901 million in 2006; $1.5 billion in 2007; $486 million in 2008; $591 million in 2009, and $243 million in 2010.
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. Alabama Power, Gulf Power, and Savannah Electric have mortgages that secure first mortgage bonds they have issued and constitute a direct first lien on substantially all of their respective fixed property and franchises. Mississippi Power discharged its mortgage in June 2005, and the lien was removed. The Georgia Power lien was removed in 2002. The remaining outstanding first mortgage bonds of Gulf Power and Savannah Electric mature in 2006. 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 2006, unused credit arrangements with banks totaled $3.3 billion, of which $810 million expires during 2006 and $2.5 billion expires during 2007 and beyond. The following table outlines the credit arrangements by company:
                                 
                    Expires
                            2007 &
Company   Total   Unused   2006   beyond
    (in millions)
Alabama Power
  $ 878     $ 878     $ 428     $ 450  
Georgia Power
    780       778       70       710  
Gulf Power
    121       121       121        
Mississippi Power
    326       276       101       225  
Savannah Electric
    80       80       60       20  
Southern Company
    750       750             750  
Southern Power
    400       399             400  
Other
    30       30       30        
 
Total
  $ 3,365     $ 3,312     $ 810     $ 2,555  
 
     Approximately $228 million of the credit facilities expiring in 2006 allow the execution of term loans for an additional two-year period, and $311 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates.
     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 one-eighth of 1 percent or less for Southern Company, the retail operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal. Included in the total $3.3 billion of unused credit arrangements is $2.3 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, 2005, Southern Company, Southern Power, and the retail operating companies were each in

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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. The cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has such credit arrangements. Southern Company and its subsidiaries are currently in compliance with all such covenants. Borrowings under certain retail operating companies’ unused credit arrangements totaling $10 million would be prohibited if the borrower experiences a material adverse change, as defined in such arrangements.
     A portion of the $3.3 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, 2005 was $720 million.
     Southern Company, the retail operating companies, and Southern Power borrow primarily 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 various other arrangements with banks and extendible commercial note programs. The amount of commercial paper outstanding and included in notes payable in the balance sheets at December 31, 2005 and December 31, 2004 was $944 million and $377 million, respectively.
     During 2005, the peak amount outstanding for short-term debt was $1.26 billion, and the average amount outstanding was $738 million. The average annual interest rate on short-term debt was 3.5 percent for 2005 and 1.3 percent for 2004 and 2003.
Financial Instruments
The retail operating companies and Southern Power 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. In addition, Southern Company Gas had gas-hedging programs to substantially mitigate its exposure to price volatility for its gas purchases.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts  
 
    (in millions)  
Regulatory liabilities, net
  $ 103.4  
Other comprehensive income
    (0.3 )
Net income
    (2.6 )
 
Total fair value
  $ 100.5  
 
     The fair value gains or losses for 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, 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 2005, 2004, and 2003, approximately $7 million, $(3) million, and $22 million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to fuel expense. For the year 2006, no material amounts 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 2008.
     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, 2005, Southern Company had $2.8 billion notional amount of interest rate swaps and options outstanding with net fair value gains of $31.7 million as follows:

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Fair Value Hedges
                             
        Variable       Fair
        Rate     Notional   Value
Company   Maturity   Paid     Amount   Gain
                (in millions)  
Southern Company
                           
 
2007
  6-month   $ 400     $ 3.0  
 
      LIBOR - 0.10%                
Cash Flow Hedges
                             
        Weighted Average           Fair
        Fixed           Value
        Rate   Notional   Gain/
Company   Maturity   Paid   Amount   (Loss)
                (in millions)
Alabama Power
                           
 
  2007     2.01 %*   $ 536     $ 7.3  
 
  2006     1.89 %     195       2.5  
 
  2016     4.82 %     300       3.0  
 
  2016     4.42 %     300       12.5  
 
Georgia Power
                           
 
  2006-2007     2.09-3.85 %**     400       1.2  
 
  2037     4.58-5.75 %***     300       (1.1 )
 
  2007     2.67 %     300       2.4  
 
Savannah Electric
                           
 
  2007     2.50 %*     14       0.3  
 
  2016     4.69 %     30       0.6  
 
*   Hedged using the Bond Market Association Municipal Swap Index.
 
**   Series of interest rate caps and collars (showing the lowest floor and highest cap) with variable rates based on one-month LIBOR.
 
***   Interest rate collar.
     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 2005, 2004, and 2003, the Company incurred losses of $19 million, $7 million, and $116 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 2005, 2004, and 2003, approximately $10 million, $23 million, and $26 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2006, pre-tax losses of approximately $2 million are expected to be reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $2.8 billion in 2006, $3.6 billion in 2007, and $3.1 billion in 2008. These amounts include $63 million, $39 million, and $23 million in 2006, 2007, and 2008, 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 regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the ongoing construction program, which includes capital improvements to generation, transmission, and distribution facilities, including those to meet environmental standards.
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 provide 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

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operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.8 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.
     Georgia Power has also entered into an LTSA with GE through 2014 for $14.9 million worth of neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $13.1 million. The contract contains cancellation provisions at the option of Georgia Power.
     Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed by GE is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work.
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, 2005. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2005 were as follows:
                                 
    Commitments
    Natural     Nuclear   Purchased
    Gas   Coal   Fuel   Power
    (in millions)
2006
  $ 1,495     $ 3,129     $ 63     $ 175  
2007
    805       2,509       39       176  
2008
    481       1,450       23       180  
2009
    371       864       14       162  
2010
    369       694       20       143  
2011 and thereafter
    3,046       364       89       541  
 
Total
  $ 6,567     $ 9,010     $ 248     $ 1,377  
 
     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 for 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 $11 million for the fair market value of this residual value guarantee is included in the balance sheet as of December 31, 2005.
     Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $150 million, $156 million, and $172 million for 2005, 2004, and 2003, respectively. Southern Company includes any step

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rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. At December 31, 2005, estimated minimum lease payments for noncancelable operating leases were as follows:
                                 
    Minimum Lease Payments  
    Plant     Rail              
    Daniel     Cars     Other     Total  
            (in millions)              
2006
  $ 29     $ 42     $ 52     $ 123  
2007
    29       34       46       109  
2008
    29       31       36       96  
2009
    29       24       30       83  
2010
    28       22       23       73  
2011 and thereafter
    28       84       147       259  
 
Total
  $ 172     $ 237     $ 334     $ 743  
 
     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, $20 million, and $68 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
Prior to the spin-off, Southern Company 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, 2005 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.
8. COMMON STOCK
Stock Issued
Southern Company raised $213 million (10 million shares) in 2005 and $124 million (7 million shares) in 2004 from the issuance of new common shares under the Company’s various stock plans.
Stock Repurchased
During 2005, in a program designed primarily to offset the issuances discussed above, Southern Company repurchased 10 million shares of common stock at a total cost of $352 million. The repurchase program was discontinued in early January 2006.
Shares Reserved
At December 31, 2005, a total of 64.9 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, 2005, 6,329 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 2003 to 2005 for the stock option plan is summarized below:

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
 
Balance at December 31, 2002
    32,674,814       19.72  
Options granted
    7,165,190       27.98  
Options canceled
    (181,381 )     24.37  
Options exercised
    (5,725,336 )     16.56  
 
Balance at December 31, 2003
    33,933,287       21.97  
Options granted
    7,231,703       29.49  
Options canceled
    (72,794 )     26.85  
Options exercised
    (6,557,690 )     18.11  
 
Balance at December 31, 2004
    34,534,506       24.27  
Options granted
    6,969,083       32.71  
Options canceled
    (83,366 )     28.01  
Options exercised
    (10,072,868 )     21.17  
 
Balance at December 31, 2005
    31,347,355     $ 27.13  
 
 
               
Shares reserved for future grants:
               
At December 31, 2003
    39,751,477          
At December 31, 2004
    32,583,523          
At December 31, 2005
    25,687,333          
 
Options exercisable:
               
At December 31, 2003
    18,874,426          
At December 31, 2004
    21,782,064          
At December 31, 2005
    18,535,238          
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price  
    Range of Options  
    13-21     21-28     28-35  
 
Outstanding:
                       
Shares (in thousands)
    4,157       13,370       13,821  
Average remaining life (in years)
    4.2       5.9       8.2  
Average exercise price
  $ 17.25     $ 26.10     $ 31.10  
Exercisable:
                       
Shares (in thousands)
    4,157       11,465       2,914  
Average exercise price
  $ 17.25     $ 25.79     $ 29.67  
 
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  
    2005     2004     2003  
      (in thousands)
As reported shares
    743,927       738,879       726,702  
Effect of options
    4,600       4,197       5,202  
 
Diluted shares
    748,527       743,076       731,904  
 
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2005, consolidated retained earnings included $4.5 billion of undistributed retained earnings of the subsidiaries. Of this amount, $68 million was restricted against the payment of cash dividends on common stock by Savannah Electric under terms of its bond indenture. Southern Power’s credit facility also contains potential limitations on the payment of common stock dividends; as of December 31, 2005, Southern Power was in compliance with all such requirements.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendment Act (Act), 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 $15 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 $30 million per company to be paid for each incident in any one year.
     Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
     Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
     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 $41 million and $48 million, respectively.
     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, 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, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property 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 nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.
     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 retail operating companies and Southern Power. Net income and total assets for discontinued operations are included in the reconciling eliminations column. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in synthetic fuels and leveraged lease projects, telecommunications, and energy-related services. Southern Power’s revenues from sales to the retail operating companies were $557 million, $425 million, and $313 million in 2005, 2004, and 2003, 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:

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
Business Segment
                                                         
    Electric Utilities            
    Retail                                
    Operating   Southern                   All        
    Companies   Power   Eliminations   Total   Other   Eliminations   Consolidated
                            (in millions)                        
2005
                                                       
Operating revenues
  $ 13,156     $ 781     $ (659 )   $ 13,278     $ 393     $ (117 )   $ 13,554  
Depreciation and amortization
    1,083       54             1,137       39             1,176  
Interest income
    30       2             32       5       (1 )     36  
Interest expense
    567       79             646       101             747  
Income taxes
    827       72             899       (304 )           595  
Segment net income (loss)
    1,398       115             1,513       80       (2 )     1,591  
Total assets
    36,335       2,303       (179 )     38,459       1,751       (333 )     39,877  
Gross property additions
    2,177       241             2,418       58             2,476  
 
                                                         
    Electric Utilities            
    Retail                                
    Operating   Southern                   All        
    Companies   Power   Eliminations   Total   Other   Eliminations   Consolidated
                            (in millions)                        
2004
                                                       
Operating revenues
  $ 11,300     $ 701     $ (536 )   $ 11,465     $ 375     $ (111 )   $ 11,729  
Depreciation and amortization
    857       51             908       41             949  
Interest income
    24       1             25       4       (2 )     27  
Interest expense
    518       66             584       83             667  
Income taxes
    802       73             875       (290 )           585  
Segment net income (loss)
    1,309       112             1,421       109       2       1,532  
Total assets
    33,517       2,067       (104 )     35,480       1,895       (420 )     36,955  
Gross property additions
    2,307       116       (415 )     2,008       91             2,099  
 
                                                         
    Electric Utilities            
    Retail                                
    Operating   Southern                   All        
    Companies   Power   Eliminations   Total   Other   Eliminations   Consolidated
                            (in millions)                        
2003
                                                       
Operating revenues
  $ 10,502     $ 682     $ (437 )   $ 10,747     $ 357     $ (86 )   $ 11,018  
Depreciation and amortization
    933       39             972       49       1       1,022  
Interest income
    33                   33       6       (3 )     36  
Interest expense
    542       32             574       108       (4 )     678  
Income taxes
    760       85             845       (228 )     1       618  
Segment net income (loss)
    1,269       155             1,424       59       (9 )     1,474  
Total assets
    31,503       2,409       (122 )     33,790       1,574       (189 )     35,175  
Gross property additions
    1,636       344             1,980       34             2,014  
 
Products and Services
                                 
    Electric Utilities Revenues
Year   Retail   Wholesale   Other   Total
    (in millions)
 
2005
  $ 11,165     $ 1,667     $ 446     $ 13,278  
2004
    9,732       1,341       392       11,465  
2003
    8,875       1,358       514       10,747  
 

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report
11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2005 and 2004 — including discontinued operations for net income and earnings per share — 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 2005
  $ 2,787     $ 560     $ 323     $ 0.43     $ 0.3575     $ 34.08     $ 31.25  
June 2005
    3,120       721       387       0.52       0.3725       34.91       31.78  
September 2005
    4,358       1,277       722       0.97       0.3725       36.16       33.47  
December 2005
    3,289       404       159       0.21       0.3725       36.07       33.28  
 
March 2004
  $ 2,651     $ 615     $ 331     $ 0.45     $ 0.3500     $ 30.87     $ 29.10  
June 2004
    2,984       697       352       0.48       0.3500       30.59       27.86  
September 2004
    3,424       1,120       645       0.87       0.3575       30.65       28.86  
December 2004
    2,670       389       204       0.28       0.3575       33.92       29.95  
 
Southern Company’s business is influenced by seasonal weather conditions.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2001 through 2005
Southern Company and Subsidiary Companies 2005 Annual Report
                                         
    2005   2004   2003   2002   2001
 
Operating Revenues (in millions)
  $ 13,554     $ 11,729     $ 11,018     $ 10,447     $ 10,155  
Total Assets (in millions)
  $ 39,877     $ 36,955     $ 35,175     $ 33,721     $ 31,856  
Gross Property Additions (in millions)
  $ 2,476     $ 2,099     $ 2,014     $ 2,728     $ 2,617  
Return on Average Common Equity (percent)
    15.17       15.38       16.05       15.79       13.51  
Cash Dividends Paid Per Share of Common Stock
  $ 1.475     $ 1.415     $ 1.385     $ 1.355     $ 1.340  
 
Consolidated Net Income (in millions):
                                       
Continuing Operations
  $ 1,591     $ 1,529     $ 1,483     $ 1,315     $ 1,120  
Discontinued Operations
          3       (9 )     3       142  
 
Total
  $ 1,591     $ 1,532     $ 1,474     $ 1,318     $ 1,262  
 
Earnings Per Share From Continuing Operations —
                                       
Basic
  $ 2.14     $ 2.07     $ 2.04     $ 1.86     $ 1.62  
Diluted
    2.13       2.06       2.03       1.85       1.61  
Earnings Per Share Including Discontinued Operations —
                                       
Basic
  $ 2.14     $ 2.07     $ 2.03     $ 1.86     $ 1.83  
Diluted
    2.13       2.06       2.02       1.85       1.82  
 
Capitalization (in millions) :
                                       
Common stock equity
  $ 10,689     $ 10,278     $ 9,648     $ 8,710     $ 7,984  
Preferred and preference stock
    596       561       423       298       368  
Mandatorily redeemable preferred securities
                1,900       2,380       2,276  
Long-term debt payable to affiliated trusts
    1,888       1,961                    
Long-term debt
    10,958       10,488       10,164       8,714       8,297  
 
Total (excluding amounts due within one year)
  $ 24,131     $ 23,288     $ 22,135     $ 20,102     $ 18,925  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    44.3       44.1       43.6       43.3       42.2  
Preferred and preference stock
    2.5       2.4       1.9       1.5       1.9  
Mandatorily redeemable preferred securities
                8.6       11.8       12.0  
Long-term debt payable to affiliated trusts
    7.8       8.4                    
Long-term debt
    45.4       45.1       45.9       43.4       43.9  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Other Common Stock Data:
                                       
Book value per share
  $ 14.42     $ 13.86     $ 13.13     $ 12.16     $ 11.43  
Market price per share:
                                       
High
    36.160       33.920       31.810       30.850       26.000  
Low
    31.250       27.860       27.710       23.890       16.152  
Close
    34.530       33.520       30.250       28.390       25.350  
Market-to-book ratio (year-end) (percent)
    239.5       241.8       230.4       233.5       221.8  
Price-earnings ratio (year-end) (times)
    16.1       16.2       14.8       15.3       15.6  
Dividends paid (in millions)
  $ 1,098     $ 1,044     $ 1,004     $ 958     $ 922  
Dividend yield (year-end) (percent)
    4.3       4.2       4.6       4.8       5.3  
Dividend payout ratio (percent)
    69.0       68.3       67.7       72.8       82.4  
Shares outstanding (in thousands):
                                       
Average
    743,927       738,879       726,702       708,161       689,352  
Year-end
    741,448       741,495       734,829       716,402       698,344  
Stockholders of record (year-end)
    118,285       125,975       134,068       141,784       150,242  
 
Retail Operating Company Customers (year-end) (in thousands):
                                       
Residential
    3,642       3,600       3,552       3,496       3,441  
Commercial
    586       578       564       553       539  
Industrial
    15       14       14       14       14  
Other
    5       5       6       5       4  
 
Total
    4,248       4,197       4,136       4,068       3,998  
 
Employees (year-end)
    25,554       25,642       25,762       26,178       26,122  
 

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2001 through 2005
Southern Company and Subsidiary Companies 2005 Annual Report
                                         
    2005   2004   2003   2002   2001
 
Operating Revenues (in millions):
                                       
Residential
  $ 4,376     $ 3,848     $ 3,565     $ 3,556     $ 3,247  
Commercial
    3,904       3,346       3,075       3,007       2,966  
Industrial
    2,785       2,446       2,146       2,078       2,144  
Other
    100       92       89       87       83  
 
Total retail
    11,165       9,732       8,875       8,728       8,440  
Sales for resale
    1,667       1,341       1,358       1,168       1,174  
 
Total revenues from sales of electricity
    12,832       11,073       10,233       9,896       9,614  
Other revenues
    722       656       785       551       541  
 
Total
  $ 13,554     $ 11,729     $ 11,018     $ 10,447     $ 10,155  
 
Kilowatt-Hour Sales (in millions):
                                       
Residential
    51,082       49,702       47,833       48,784       44,538  
Commercial
    51,857       50,037       48,372       48,250       46,939  
Industrial
    55,141       56,399       54,415       53,851       52,891  
Other
    996       1,005       998       1,000       977  
 
Total retail
    159,076       157,143       151,618       151,885       145,345  
Sales for resale
    37,801       35,239       40,520       32,551       30,768  
 
Total
    196,877       192,382       192,138       184,436       176,113  
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    8.57       7.74       7.45       7.29       7.29  
Commercial
    7.53       6.69       6.36       6.23       6.32  
Industrial
    5.05       4.34       3.94       3.86       4.05  
Total retail
    7.02       6.19       5.85       5.75       5.81  
Sales for resale
    4.41       3.81       3.35       3.59       3.82  
Total sales
    6.52       5.76       5.33       5.37       5.46  
Average Annual Kilowatt-Hour
                                       
Use Per Residential Customer
    14,084       13,879       13,562       14,036       13,014  
Average Annual Revenue
                                       
Per Residential Customer
  $ 1,207     $ 1,074     $ 1,011     $ 1,023     $ 949  
Plant Nameplate Capacity
                                       
Ratings (year-end) (megawatts)
    40,502       38,622       38,679       36,353       34,579  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    30,384       28,467       31,318       25,939       26,272  
Summer
    35,050       34,414       32,949       32,355       29,700  
System Reserve Margin (at peak) (percent)
    14.4       20.2       21.4       13.3       19.3  
Annual Load Factor (percent)
    60.2       61.4       62.0       51.1       62.0  
Plant Availability (percent):
                                       
Fossil-steam
    89.0       88.5       87.7       84.8       88.1  
Nuclear
    90.5       92.8       94.4       90.3       90.8  
 
Source of Energy Supply (percent):
                                       
Coal
    67.0       64.6       66.4       65.7       67.5  
Nuclear
    13.9       14.4       14.8       14.7       15.2  
Hydro
    3.1       2.9       3.8       2.6       2.6  
Oil and gas
    10.9       10.9       8.8       11.4       8.4  
Purchased power
    5.1       7.2       6.2       5.6       6.3  
 
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 (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, 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, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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-100 to II-127) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP

Birmingham, Alabama
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2005 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 rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and restoration following major storms.
     On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the Company’s service territory including the Company’s distribution and transmission facilities. Approximately 241,000 and 637,000, respectively, of the Company’s 1.4 million customers were without electrical service immediately after Hurricanes Dennis and Katrina.
     In 2005, the Company successfully completed a retail rate proceeding with the Alabama Public Service Commission (PSC) to recover the costs associated with these storms and to replenish the Company’s natural disaster reserve. In other actions, the Alabama PSC also approved a higher fuel recovery rate and amended the Company’s Rate Stabilization and Equalization Plan (Rate RSE) to use forward-looking test periods. These regulatory actions are expected to assist the Company’s continued focus on providing reliable electrical service to customers while maintaining a stable financial position.
Key Performance Indicators
In striving to maximize shareholder value while providing cost effective energy to customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. 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 customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro 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. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects. The 2005 Peak Season EFOR exceeded target levels primarily due to equipment malfunctions at Plant Barry units 5 and 6, which resulted in unexpected outages. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2005 performance was above target on these reliability measures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2005 results compared with its targets for each of these indicators are reflected in the following chart.
         
Key   2005   2005
Performance Indicator   Target Performance   Actual Performance
Customer Satisfaction
  Top quartile in customer surveys   Top quartile
Peak Season EFOR
  2.75% or less   3.83%
Net Income
  $501 million   $508 million
     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 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 financial performance remained strong in 2005 despite the challenges of major hurricane restorations and rising fuel costs. The Company’s net income after dividends on preferred stock of $508 million in 2005 increased $27 million (5.6 percent) over the prior year. This improvement is primarily due to retail and wholesale revenue growth, increases in transmission revenues, partially offset by higher non-fuel operating expenses.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
     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 was primarily due to retail sales growth, 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 customer fees revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.
     The ROE for 2005 was 13.72 percent compared to 13.53 percent in 2004 and 13.75 percent in 2003.
RESULTS OF OPERATIONS
A condensed income statement is as follows:
                                 
            Increase (Decrease)
    Amount   From Prior Year
    2005   2005   2004   2003
    (in millions)
Operating revenues
  $ 4,648     $ 412     $ 276     $ 250  
 
Fuel
    1,457       271       119       98  
Purchased power
    457       44       98       66  
Other operation and maintenance
    1,044       97       26       67  
Depreciation and amortization
    427       1       13       15  
Taxes other than income taxes
    249       6       14       11  
 
Total operating expenses
    3,634       419       270       257  
 
Operating income
    1,014       (7 )     6       (7 )
Total other income and (expense)
    (197 )     6       30       20  
Income taxes
    285       (29 )     23       (2 )
 
Net income
    532       28       13       15  
Dividends on preferred stock
    24       1       5       3  
 
Net income after dividends on preferred stock
  $ 508     $ 27     $ 8     $ 12  
 
Revenues
Operating revenues for 2005 were $4.6 billion, reflecting a $412 million increase from 2004. The following table summarizes the principal factors that have affected operating revenues for the past three years:
                         
    Amount
    2005   2004   2003
    (in millions)
Retail — prior year
  $ 3,293     $ 3,051     $ 2,951  
Change in -
                       
Base rates
    35       41       51  
Sales growth
    50       48       68  
Weather
    18       12       (61 )
Fuel cost recovery and other
    225       141       42  
 
Retail — current year
    3,621       3,293       3,051  
 
Sales for resale —
                       
Non-affiliates
    551       484       488  
Affiliates
    289       308       277  
 
Total sales for resale
    840       792       765  
 
Other operating revenues
    187       151       144  
 
Total operating revenues
  $ 4,648     $ 4,236     $ 3,960  
 
Percent change
    9.7 %     7.0 %     6.7 %
 
     Retail revenues in 2005 were $3.6 billion. Revenues increased $328 million (10.0 percent) in 2005, $242 million (7.9 percent) in 2004, and $100 million (3.4 percent) in 2003. These increases were primarily due to increased fuel revenue and retail base rate increases of 0.5 percent in April 2005, 1.0 percent in January 2005, 0.8 percent in July 2004, and 2.6 percent in July 2003. See FUTURE EARNINGS POTENTIAL – “PSC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
     Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.
     Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities. Revenues from unit 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:

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
                         
    2005   2004   2003
    (in thousands)
Unit power -
                       
Capacity
  $ 147,609     $ 134,615     $ 130,022  
Energy
    169,080       146,809       145,342  
 
Total
  $ 316,689     $ 281,424     $ 275,364  
 
     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 the energy. Revenues associated with other power sales to non-affiliates were as follows:
                         
    2005   2004   2003
    (in thousands)
Other power sales -
                       
Capacity and other
  $ 116,181     $ 90,673     $ 96,263  
Variable cost of energy
    118,537       111,742       115,829  
 
Total
  $ 234,718     $ 202,415     $ 212,092  
 
     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 Intercompany Interchange Contract (IIC) as approved by the Federal Energy Regulatory Commission (FERC). In 2005, sales for resale revenues decreased $19.4 million primarily due to a 20.7 percent decrease in kilowatt-hour sales to affiliates as a result of a decrease in the availability of the Company’s generating resources due to an increase in customer demand within the Company’s service territory. Sales for resale revenues increased $31.1 million in 2004 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 2005 increased $35.0 million (23.2 percent) from 2004 due to an increase of $20 million in revenues from gas-fueled co-generation steam facilities primarily as a result of higher gas prices, and $7.7 million increase in transmission revenues and a $3.9 million increase from rent from associated companies primarily related to leased transmission facilities.
     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.
     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 PSC approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002.
     Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2005 and the percent change by year were as follows:
                                 
    KWH   Percent Change
    2005   2005   2004   2003
    (millions)                        
Residential
    18,074       4.1 %     2.4 %     (2.5 )%
Commercial
    14,062       1.7       2.8       0.7  
Industrial
    23,350       2.2       5.8       2.3  
Other
    198       0.2       (2.4 )     (1.1 )
 
                               
Total retail
    55,684       2.7       3.9       0.3  
Sales for resale —  
                               
Non-affiliates
    15,443       (0.3 )     (9.4 )     9.9  
Affiliates
    5,735       (20.7 )     (23.2 )     6.5  
 
                               
Total
    76,862       (0.1 )     (2.2 )     2.9  
 
     Retail energy sales in 2005 were 2.7 percent higher than 2004 despite interruptions during Hurricanes Dennis and Katrina. Energy sales in the residential sector led the growth with a 4.1 percent increase in 2005 due primarily to increased demand. Commercial sales increased 1.7 percent in 2005 primarily due to continued customer growth. Industrial sales increased 2.2 percent during the

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
year with chemical, primary metals and automotive leading the growth in industrial energy consumption. In addition, the paper sector chose to purchase rather than self-generate which contributed to increased sales.
     Energy sales in the residential sector grew by 2.4 percent in 2004 primarily due to continued customer growth and a return to normal summer temperatures. Commercial sales increased 2.8 percent in 2004 primarily due to continued customer growth. Industrial sales rebounded 5.8 percent during the year with primary metals, 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 effect of sluggish economic conditions.
     Assuming normal weather, sales to retail customers are projected to grow approximately 1.3 percent annually on average during 2006 through 2010.
Total Operating Expenses
In 2005 total operating expenses increased $419 million (13.0 percent) to $3.6 billion. This change from 2004 includes an increase in fuel expense of $271 million (22.8 percent) related to higher natural gas and coal prices. In addition, purchased power expenses increased $45 million (10.8 percent) primarily due to a 17.9 percent increase in purchased power prices. Maintenance expenses increased $48 million primarily from transmission and distribution expense. These increases are mainly a result of the Alabama PSC accounting order to recognize the previously deferred costs of Hurricane Ivan storm damage restoration and to partially replenish a balance in the natural disaster reserve. See Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Cost Recovery” for additional information.
     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.
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 fossil and nuclear generating units and hydro generation. The amount and sources of generation and the average cost of fuel per net KWH generated and the average cost of purchased power were as follows:
                         
    2005   2004   2003
Total generation
                       
(billions of KWHs)
    71       70       72  
Sources of generation
                       
(percent) —
                       
Coal
    67       65       64  
Nuclear
    19       19       19  
Hydro
    6       6       8  
Gas
    8       10       9  
Average cost of fuel per net KWH generated (cents)
    2.02       1.69       1.54  
Average cost of purchased power per net KWH (cents)
    6.49       4.79       3.61  
 
     Fuel expense increased 22.8 percent in 2005 primarily due to an increase in the average cost of fuel as a result of a 26.5 percent increase in the average price of natural gas and an 18.5 percent increase in the average coal price. Fuel expense increased 11.1 percent in 2004 primarily due to a 30.5 percent increase in the average price of natural gas and a 3.1 percent increase in the average price of coal. Fuel expense increased 10.1 percent in 2003 due to a 58.3 percent increase in the average price of natural gas and a 2.2 percent increase in the average price of coal.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
     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 and the availability and variable production cost of generating resources at each company. Purchased power from non-affiliates increased $2.5 million (1.0 percent) in 2005. This was due to a 14.3 percent increase in purchased power prices over the previous year. In 2004, purchased power from non-affiliates increased $75 million (68 percent) due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices compared to 2003. 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.
     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 increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an immediate market response; however, the long-term 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. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. See Future Earnings Potential — “PSC Matters – Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.
Other Expenses
Depreciation and amortization expense increased 0.1 percent in 2005, 3.1 percent in 2004, and 3.6 percent in 2003. These increases reflect additions to property, plant, and equipment.
     Allowance for equity funds used during construction (AFUDC) increased $4.1 million (25.6 percent) and $3.5 million (28.2 percent) in 2005 and 2004, respectively, primarily due to increases in the amount of construction work in progress over the prior year. AFUDC also increased $1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate. See Note 1 to the financial statements under “AFUDC” for additional information.
     In 2005 interest expense, net of amounts capitalized increased $3.8 million to $197.4 million due to an increase in average debt outstanding during the year. This reversed the trend of the past two years when refinancing activities resulted in $20.7 million (9.7 percent) and $11.4 million (5.1 percent) decreases in 2004 and 2003, respectively.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of costs. When historical costs are included, or when inflation exceeds projected costs used, in rate regulation, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been substantial. 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 may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” 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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
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 that continues to allow for the recovery of all prudently incurred costs. 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.
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 Northern District of Georgia granted the Company’s motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, the Company and the EPA are currently participating in mediation with respect to the EPA’s claims.
     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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Alabama’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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

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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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
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. Applicable statutes 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 these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $961 million in capital projects to comply with these requirements, with annual totals of $256 million, $177 million, and $100 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $2.2 billion, including $285 million, $426 million, and $406 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $745 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2 and NOx emissions, maintain compliance with existing regulations, and to meet new requirements.
     Approximately $594 million of these expenditures related to reducing NOx emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NOx reduction rules. In 2004, the regional NOx reduction rules were implemented for the northern two-thirds of Alabama. See Note 3 to the financial statements under “Retail Regulatory Matters” for information regarding the Company’s recovery of costs associated with environmental laws and regulations.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. The area within the Company’s service area that has been designated as nonattainment under the eight-hour ozone standard includes Jefferson and Shelby Counties, near Birmingham. State implementation plans, including new emission control regulations necessary to bring those areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NOx emissions from power plants.
     In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment. The final outcome of this matter cannot now be determined.

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     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within the Company’s service area, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses SO2 and NOx emissions from power plants that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emissions allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the eight-hour ozone standard, the fine particulate matter designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2, NOx, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.
     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

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Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release 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.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 — 2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an

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adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 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. These proceedings are still pending at the FERC. The Company has also received similar requests from other entities totaling approximately $7 million. The Company has opposed all such requests. 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.
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 “Market-Based Rate Authority” and “Generation Interconnection Agreements” 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.
Hydro Relicensing
In July 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expire in 2007.
     In 2006, the Company will initiate the process of developing a relicensing application for the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013.

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     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 these matters 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. In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved the Company’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. See Note 1 to the financial statements under “Nuclear Decommissioning” for additional information.
PSC Matters
Retail Rate Adjustments
In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate RSE” for further information.
     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). In October 2004, the Alabama PSC amended Rate CNP to also allow 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 is calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 1.0 percent in January 2005 and 1.2 percent in January 2006. It is currently anticipated that retail rates will increase approximately 0.5 percent in 2007. In conjunction with the Alabama PSC’s approval of this rate mechanism, the Company agreed to a moratorium through 2006 on retail rate increases under Rate RSE.
     Effective July 2003, the Company’s retail rates were adjusted by approximately 2.6 percent under Rate CNP as a result of two new certificated PPAs that began in June 2003. An additional increase of 0.8 percent in retail rates, or $25 million annually, was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. The projected annual true-up adjustment to be effective in April 2006 is expected to increase retail rates by 0.5 percent, or $19 million annually. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate CNP” for additional information.
Retail Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Alabama PSC. As a result of increased fuel costs for coal and gas, the Company filed a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). In December 2005, the Alabama PSC approved an increase of the energy billing factor for retail customers from 1.788 cents per KWH to 2.400 cents per KWH, effective with billings beginning January 2006. This change to the billing factor represents on average an increase of approximately $6.12 per month for a customer billing of 1,000 KWHs. This approved increase was intended to allow for the recovery of energy costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2007. In addition, during 2007, the

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Company will be allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. As a result of the order, the Company reclassified $186.9 million of the under-recovered regulatory clause revenues from current assets to deferred charges and other assets in the balance sheet as of December 31, 2005. See Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.
     Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this approved increase in the billing factor will have no significant effect on the Company’s revenues or net income, but will increase annual cash flow.
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 facilities. On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.
     In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately $28 million), which resulted in a negative balance in the natural disaster reserve (NDR). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately $30 million). See Note 1 and Note 3 to the financial statements under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, for additional information on these reserves. The natural disaster reserve deficit balance at December 31, 2005 was $50.6 million.
     In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24-month period. The maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.
     As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income but will increase the annual cash flow.
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $21 million, $36 million, and $52 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $28 million, $22 million, and $23 million in 2005, 2004, and 2003, respectively. Both pension and postretirement benefit costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension 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.

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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. Management has reviewed and discussed critical accounting policies and estimates 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 (Statement No. 71), 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 and accounting principles generally accepted in the United States. 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.

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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
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $35 million. The adoption of FIN 47 did not have any effect on the Company’s income statement.
Stock Options
On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition continued to be strong at December 31, 2005. Net cash flow from operating activities totaled $0.9 billion, $1.0 billion, and $1.1 billion for 2005, 2004, and 2003, respectively. The $106 million decrease for 2005 in operating activities primarily relates to an increase in under recovered fuel cost and storm damage costs related to Hurricanes Dennis and Katrina. These increases were partially offset by the deferral of income tax liabilities arising from accelerated depreciation deductions. The $104 million decrease from 2003 to 2004 resulted from under recovered fuel cost and storm damage costs related to Hurricane Ivan partially offset by accelerated depreciation reductions. Fuel and storm damage costs are recoverable in future periods. Under recovered fuel cost is included in the balance sheets as under recovered regulatory clause revenue and deferred under recovered regulatory clause revenues. Under recovered storm damage cost is included in the balance sheets as other current assets and other regulatory assets. See FUTURE EARNINGS POTENTIAL — “Fuel Cost Recovery” and “Natural Disaster Cost Recovery” herein for additional information.
     Significant balance sheet changes for 2005 include an increase of $668 million in gross plant. In 2004 significant balance sheet changes included the $478 million increase in long-term debt primarily due to the replacement of debt due within one year with long-term debt, and an increase of $408 million in gross plant.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
     The Company’s ratio of common equity to total capitalization — including short-term debt — was 42.2 percent in 2005, 42.6 percent in 2004, and 43.3 percent in 2003. 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 from sources similar to those used in the past, which were primarily from operating cash flows. In recent years, the Company has primarily utilized unsecured debt, preferred stock, and preferred securities. However, the type and timing of any financings — if needed — will depend on market conditions and regulatory approval.
     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. 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 the Company are not commingled with funds of any other company.
     The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as 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 2006, the Company had approximately $22 million of cash and cash equivalents and $878 million of unused credit arrangements with banks, as described below. 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 $878 million, of which $428 million will expire at various times during 2006. $251 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional one-year period. 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.
     As of December 31, 2005 the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement. As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding.
Financing Activities
During 2005, the Company issued $250 million of long-term debt. In addition, the Company issued one 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 repay short-term indebtedness, and for other general corporate purposes. In November 2005, the Company incurred obligations in connection with the issuance of $21.5 million of variable rate pollution control bonds. The proceeds were used to refund $21.5 million 5.50% fixed rate pollution control bonds.
     In January and February 2006, the Company issued $600 million of long-term debt. The proceeds of these issues were used to repay short-term indebtedness and for other general corporate purposes. In conjunction with these transactions, the Company terminated $600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
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 risk management activities. At December 31, 2005, the Company’s exposure to these agreements was not material.
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 future exposure to changes in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. The weighted average interest rate on $271.5 million of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.45 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 $2.7 million at January 1, 2006. 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, 2005, exposure from these activities was not material to the Company’s financial position, results of operations, or cash flows. The changes in fair value of energy related derivative contracts and year-end valuations were as follows at December 31:
                 
    Changes in Fair Value
    2005   2004
    (in thousands)
Contracts beginning of year
  $ 4,017     $ 6,413  
Contracts realized or settled
    (38,320 )     (26,384 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    63,281       23,988  
 
Contracts end of year
  $ 28,978     $ 4,017  
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2005 Year-End
    Valuation Prices
    Total   Maturity
    Fair Value   2006   2007-2008
    (in thousands)
 
Actively quoted
  $ 29,177     $ 19,392     $ 9,785  
External sources
    (199 )     (199 )      
Models and other methods
                 
 
Contracts end of Year
  $ 28,978     $ 19,193     $ 9,785  
 
     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, 2005, the fair

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 29,044  
Other comprehensive income
     
Net income
    (66 )
 
Total fair value
  $ 28,978  
   
     Unrealized pre-tax gains (losses) on energy contracts 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. 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 $0.9 billion for 2006, $1.1 billion for 2007, and $1.1 billion for 2008. Environmental expenditures included in these amounts are $285 million, $426 million, and $406 million for 2006, 2007, and 2008, respectively (including $305 million on selective catalytic reduction facilities and $658 million on scrubbers). In addition, over the next three years, the Company estimates spending $244 million on Plant Farley (including $184 million for nuclear fuel), $793 million on distribution facilities, and $394 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 $1.6 billion will be required by the end of 2008 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 discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal 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 final installment is scheduled to occur in 2006.
     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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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report
                                         
Contractual Obligations                                
            2007-     2009-     After        
    2006     2008     2010     2010     Total  
    (in millions)  
Long-term debt(a)
                                       
Principal
  $ 546.7     $ 1,078.8     $ 350.1     $ 2,444.4     $ 4,420.0  
Interest
    191.7       325.3       252.7       2,165.7       2,935.4  
Commodity derivative obligations(b)
    9.3       0.1                   9.4  
Preferred stock dividends(c)
    24.3       48.6       48.6             121.5  
Operating leases
    23.6       28.5       17.0       29.1       98.2  
Purchase commitments(d)
                                       
Capital(e)
    950.9       2,208.1                   3,159.0  
Coal
    1,064.9       1,551.7       863.6       323.6       3,803.8  
Nuclear fuel
    18.3       20.0       8.6       25.5       72.4  
Natural gas(f)
    545.2       413.9       45.4       89.4       1,093.9  
Purchased power
    87.0       177.0       125.0       2.0       391.0  
Long-term service agreements
    17.8       37.0       38.4       87.4       180.6  
 
                                       
Postretirement benefits(g)
    24.9       44.6                   69.5  
DOE
    4.7                         4.7  
 
Total
  $ 3,509.3     $ 5,933.6     $ 1,749.4     $ 5,167.1     $ 16,359.4  
 
(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, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
 
(b)   For additional information, see Notes 1 and 6 to the financial statements herein.
 
(c)   Preferred stock does not mature; therefore, amounts are provided for the next five years only.
 
(d)   The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $1.04 billion, $947 million, and $921 million, respectively.
 
(e)   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, 2005, significant purchase commitments were outstanding in connection with the construction program.
 
(f)   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, 2005.
 
(g)   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)
Alabama Power Company 2005 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2005 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 and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, 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, implementation of the Energy Policy Act of 2005, 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, and FERC matters;
 
  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, including rate cases relating to fuel cost recovery;
 
  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 Securities and Exchange Commission.
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, 2005, 2004, and 2003
Alabama Power Company 2005 Annual Report
                         
    2005     2004     2003  
 
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 3,621,421     $ 3,292,828     $ 3,051,463  
Sales for resale —
                       
Non-affiliates
    551,408       483,839       487,456  
Affiliates
    288,956       308,312       277,287  
Other revenues
    186,039       151,012       143,955  
 
Total operating revenues
    4,647,824       4,235,991       3,960,161  
 
Operating Expenses:
                       
Fuel
    1,457,301       1,186,472       1,067,821  
Purchased power —
                       
Non-affiliates
    188,733       186,187       110,885  
Affiliates
    268,751       226,697       204,353  
Other operations
    682,308       634,030       611,418  
Maintenance
    361,832       313,407       309,451  
Depreciation and amortization
    426,506       425,906       412,919  
Taxes other than income taxes
    248,854       242,809       228,414  
 
Total operating expenses
    3,634,285       3,215,508       2,945,261  
 
Operating Income
    1,013,539       1,020,483       1,014,900  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    20,281       16,141       12,594  
Interest income
    17,144       15,677       15,220  
Interest expense, net of amounts capitalized
    (197,367 )     (193,590 )     (214,302 )
Interest expense to affiliate trusts
    (16,237 )     (16,191 )      
Distributions on mandatorily redeemable preferred securities
                (15,255 )
Other income (expense), net
    (20,461 )     (24,728 )     (31,702 )
 
Total other income and (expense)
    (196,640 )     (202,691 )     (233,445 )
 
Earnings Before Income Taxes
    816,899       817,792       781,455  
Income taxes
    284,715       313,024       290,378  
 
Net Income
    532,184       504,768       491,077  
Dividends on Preferred Stock
    24,289       23,597       18,267  
 
Net Income After Dividends on Preferred Stock
  $ 507,895     $ 481,171     $ 472,810  
 
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, 2005, 2004, and 2003
Alabama Power Company 2005 Annual Report
                         
    2005   2004   2003
            (in thousands)        
Operating Activities:
                       
Net income
  $ 532,184     $ 504,768     $ 491,077  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    498,914       497,010       487,370  
Deferred income taxes and investment tax credits, net
    106,765       252,858       153,154  
Deferred revenues
    (12,502 )     (11,510 )     (17,932 )
Allowance for equity funds used during construction
    (20,281 )     (16,141 )     (12,594 )
Pension, postretirement, and other employee benefits
    (22,117 )     (31,184 )     (38,953 )
Tax benefit of stock options
    17,400       10,672       8,680  
Hedge settlements
    (21,445 )     2,241       (7,957 )
Storm damage accounting order
    48,000              
Other, net
    (15,491 )     26,826       14,177  
Changes in certain current assets and liabilities —
                       
Receivables
    (255,481 )     (126,432 )     (13,416 )
Fossil fuel stock
    (44,632 )     30,130       (13,251 )
Materials and supplies
    (16,935 )     (26,229 )     (4,651 )
Other current assets
    1,199       7,438       (953 )
Accounts payable
    80,951       (31,899 )     77,128  
Accrued taxes
    (5,381 )     (24,568 )     (33,507 )
Accrued compensation
    3,273       (7,041 )     664  
Other current liabilities
    33,675       (42,544 )     29,058  
 
Net cash provided from operating activities
    908,096       1,014,395       1,118,094  
 
Investing Activities:
                       
Property additions
    (860,807 )     (768,334 )     (643,231 )
Nuclear decommissioning trust fund purchases
    (224,716 )     (269,277 )     (350,271 )
Nuclear decommissioning trust fund sales
    223,850       248,992       329,986  
Cost of removal net of salvage
    (61,314 )     (37,369 )     (35,440 )
Other
    (9,738 )     (5,008 )     1,193  
 
Net cash used for investing activities
    (932,725 )     (830,996 )     (697,763 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    315,278             (36,991 )
Proceeds —
                       
Senior notes
    250,000       900,000       1,415,000  
Preferred stock
          100,000       125,000  
Common stock
    40,000       40,000       50,000  
Capital contributions from parent company
    22,473       17,541       17,826  
Pollution control bonds
    21,450              
Redemptions —
                       
Senior notes
    (225,000 )     (725,000 )     (1,507,000 )
Pollution control bonds
    (21,450 )            
Other long-term debt
    (5 )     (1,445 )     (943 )
Payment of preferred stock dividends
    (22,759 )     (23,639 )     (18,181 )
Payment of common stock dividends
    (409,900 )     (437,300 )     (430,200 )
Other
    (2,697 )     (16,597 )     (14,775 )
 
Net cash used for financing activities
    (32,610 )     (146,440 )     (400,264 )
 
Net Change in Cash and Cash Equivalents
    (57,239 )     36,959       20,067  
Cash and Cash Equivalents at Beginning of Year
    79,711       42,752       22,685  
 
Cash and Cash Equivalents at End of Year
  $ 22,472     $ 79,711     $ 42,752  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $8,161, $6,832, and $6,367 capitalized, respectively)
  $ 179,658     $ 188,556     $ 185,272  
Income taxes (net of refunds)
    159,600       69,068       161,004  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Alabama Power Company 2005 Annual Report
                 
Assets   2005     2004  
 
              (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 22,472     $ 79,711  
Receivables —
               
Customer accounts receivable
    275,702       233,286  
Unbilled revenues
    95,039       96,486  
Under recovered regulatory clause revenues
    132,139       119,773  
Other accounts and notes receivable
    50,008       52,145  
Affiliated companies
    77,304       61,149  
Accumulated provision for uncollectible accounts
    (7,560 )     (5,404 )
Fossil fuel stock, at average cost
    102,420       57,787  
Vacation pay
    37,646       36,494  
Materials and supplies, at average cost
    244,417       237,919  
Prepaid expenses
    58,845       61,898  
Assets from risk management activities
    53,192       11,268  
Other
    52,561       11,693  
 
Total current assets
    1,194,185       1,054,205  
 
Property, Plant, and Equipment:
               
In service
    15,300,346       14,632,342  
Less accumulated provision for depreciation
    5,313,731       5,097,930  
 
 
    9,986,615       9,534,412  
Nuclear fuel, at amortized cost
    127,199       93,388  
Construction work in progress
    469,018       474,670  
 
Total property, plant, and equipment
    10,582,832       10,102,470  
 
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    46,913       45,455  
Nuclear decommissioning trusts, at fair value
    466,963       445,634  
Other
    41,457       40,942  
 
Total other property and investments
    555,333       532,031  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    388,634       316,528  
Prepaid pension costs
    515,281       489,193  
Deferred under recovered regulatory clause revenues
    186,864        
Other regulatory assets
    128,437       163,273  
Other
    138,341       123,825  
 
Total deferred charges and other assets
    1,357,557       1,092,819  
 
Total Assets
  $ 13,689,907     $ 12,781,525  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Alabama Power Company 2005 Annual Report
                 
Liabilities and Stockholder's Equity   2005     2004  
 
              (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 546,645     $ 225,005  
Notes payable
    315,278        
Accounts payable —
               
Affiliated
    190,744       141,096  
Other
    266,174       198,834  
Customer deposits
    56,709       47,664  
Accrued taxes —
               
Income taxes
    63,844       28,498  
Other
    31,692       29,688  
Accrued interest
    46,018       40,029  
Accrued vacation pay
    37,646       36,494  
Accrued compensation
    92,784       76,858  
Other
    72,991       34,289  
 
Total current liabilities
    1,720,525       858,455  
 
Long-term Debt (See accompanying statements)
    3,560,186       3,855,257  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    309,279       309,279  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,070,746       1,885,120  
Deferred credits related to income taxes
    101,678       148,395  
Accumulated deferred investment tax credits
    196,585       205,353  
Employee benefit obligations
    208,663       194,837  
Asset retirement obligations
    446,268       383,621  
Other cost of removal obligations
    600,104       597,147  
Other regulatory liabilities
    194,135       206,765  
Other
    23,966       62,045  
 
Total deferred credits and other liabilities
    3,842,145       3,683,283  
 
Total Liabilities
    9,432,135       8,706,274  
 
Cumulative Preferred Stock (See accompanying statements)
    465,046       465,047  
 
Common Stockholder’s Equity (See accompanying statements)
    3,792,726       3,610,204  
 
Total Liabilities and Stockholder’s Equity
  $ 13,689,907     $ 12,781,525  
 
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, 2005 and 2004
Alabama Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
 
              (in thousands)               (percent of total)  
Long-Term Debt:
                               
Long-term notes payable —
                               
5.49% due November 1, 2005
  $     $ 225,000                  
2.65% to 2.80% due 2006
    520,000       520,000                  
Floating rate (1.94% at 1/1/06) due 2006
    26,500       195,000                  
3.50% to 7.125% due 2007
    500,000       500,000                  
Floating rate (2.14% at 1/1/06) due 2007
    168,500                        
3.125% to 5.375% due 2008
    410,000       410,000                  
Floating rate (4.58% at 1/1/06) due 2009
    250,000       250,000                  
4.70% due 2010
    100,000       100,000                  
5.125% to 5.875% due 2011-2035
    1,575,000       1,325,000                  
 
Total long-term notes payable
  $ 3,550,000     $ 3,525,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds —
                               
Collateralized:
                               
Variable rates (2.01% to 2.16% at 1/1/06) due 2015-2017
    89,800       89,800                  
5.50% due 2024
    2,950       24,400                  
Non-collateralized:
                               
Variable rates (2.01% to 3.74% at 1/1/06) due 2021-2031
    467,390       445,940                  
 
Total other long-term debt
    560,140       560,140                  
 
Capitalized lease obligations
    564       52                  
 
Unamortized debt premium (discount), net
    (3,873 )     (4,930 )                
 
Total long-term debt (annual interest requirement — $175.4 million)
    4,106,831       4,080,262                  
Less amount due within one year
    546,645       225,005                  
 
Long-term debt excluding amount due within one year
  $ 3,560,186     $ 3,855,257       43.8 %     46.8 %
 

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STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2005 and 2004
Alabama Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
 
              (in thousands)               (percent of total)  
Long-term Debt Payable to Affiliated Trusts:
                               
4.75% to 5.5% due 2042 (annual interest requirement — $16.2 million)
    309,279       309,279       3.8       3.8  
 
Cumulative Preferred Stock:
                               
$100 par or stated value — 4.20% to 4.92%
                               
Authorized — 3,850,000 shares
                               
Outstanding — 475,115 shares
    47,610       47,611                  
$1 par value — 4.95% to 5.83%
                               
Authorized — 27,500,000 shares
                               
Outstanding — 12,000,000 shares: $25 stated value
    294,105       294,105                  
Outstanding — 1,250 shares: $100,000 stated value
    123,331       123,331                  
 
Total cumulative preferred stock (annual dividend requirement — $24.3 million)
    465,046       465,047       5.7       5.6  
 
Common Stockholder’s Equity:
                               
Common stock, par value $40 per share —
                               
Authorized - 15,000,000 shares
                               
Outstanding - 9,250,000 shares in 2005 and 8,250,000 shares in 2004
    370,000       330,000                  
Paid-in capital
    1,995,056       1,955,183                  
Retained earnings
    1,439,144       1,341,049                  
Accumulated other comprehensive income (loss)
    (11,474 )     (16,028 )                
 
Total common stockholder’s equity
    3,792,726       3,610,204       46.7       43.8  
 
Total Capitalization
  $ 8,127,237     $ 8,239,787       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, 2005, 2004, and 2003
Alabama Power Company 2005 Annual Report
                                         
                            Other    
    Common   Paid-In   Retained   Comprehensive    
    Stock   Capital   Earnings   Income (loss)   Total
 
    (in thousands)
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  
Net income after dividends on preferred stock
                507,895             507,895  
Issuance of common stock
    40,000                         40,000  
Capital contributions from parent company
          39,873                   39,873  
Other comprehensive income (loss)
                      4,554       4,554  
Cash dividends on common stock
                (409,900 )           (409,900 )
Other
                100             100  
 
Balance at December 31, 2005
  $ 370,000     $ 1,995,056     $ 1,439,144     $ (11,474 )   $ 3,792,726  
 
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Alabama Power Company 2005 Annual Report
                         
    2005     2004     2003  
 
    (in thousands)  
Net income after dividends on preferred stock
  $ 507,895     $ 481,171     $ 472,810  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(1,422), $(2,482) and $(2,301), respectively
    (2,338 )     (4,083 )     (3,785 )
Change in fair value of marketable securities, net of tax of $252
          414        
Changes in fair value of qualifying hedges, net of tax of $5,523, $(4,807) and $1,330, respectively
    9,085       (7,906 )     2,188  
Less: Reclassification adjustment for amounts included in net income, net of tax of $(1,333), $2,136 and $4,285, respectively
    (2,193 )     3,514       7,047  
 
Total other comprehensive income (loss)
    4,554       (8,061 )     5,450  
 
Comprehensive Income
  $ 512,449     $ 473,110     $ 478,260  
 
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2005 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 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). 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 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. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
     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 was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006. Both Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is subject to regulation by the FERC and the Alabama 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 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 $246 million, $224 million, and $217 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, 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 $157 million, $169 million, and $153 million during 2005, 2004, and 2003, 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 $8.2 million in 2005, $7.2 million in 2004, and $6.6 million in 2003. See Note 4 for additional information.

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NOTES (continued)
Alabama Power Company 2005 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 $31.5 million, $28.7 million, and $27.5 million in 2005, 2004 and 2003, respectively. In addition, the Company purchases synthetic fuel from AFP for use at several of the Company’s plants. Fuel purchases for 2005, 2004, and 2003 totaled $265.7 million, $236.9 million, and $209.2 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 2005, 2004 and 2003, the Company billed Southern Power $1.9 million, $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 2005, 2004 and 2003 totaled $63.6 million, $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 2005 was $81.3 million, $65.7 million in 2004, 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 in the balance sheets at December 31, 2005 and 2004. See Note 3 under “Retail Regulatory Matters” 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 $5.7 million, $5.3 million, and $4.9 million during 2005, 2004, and 2003, 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 Company provides incidental services to, and receives such services from, other Southern Company subsidiaries which are generally minor in duration and/or amount. However, with the hurricane damage experienced by Georgia Power, Gulf Power and Mississippi Power in the last two years, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, has caused an increase in these activities. The total amount of storm restoration provided to Georgia Power and Gulf Power in 2004 and to Mississippi Power in 2005 was $2.4 million, $2.3 million and $8.0 million, respectively. In 2004 and 2005, the Company received assistance from affiliated companies in the amount of $5.6 million and $5.0 million, respectively, for aid in major storm restoration. These activities were billed at cost.
     The retail operating companies, including the Company, and Southern Power 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. 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 these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. See “Retail Regulatory Matters – Fuel Cost Recovery” in Note 3 for additional information.
     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 one 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. 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

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NOTES (continued)
Alabama Power Company 2005 Annual Report
expense totaled $64 million in 2005, $61 million in 2004, and $64 million in 2003.
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:
                         
    2005   2004   Note
    (in millions)        
Deferred income tax charges
  $ 389     $ 317       (a )
Loss on reacquired debt
    102       109       (b )
DOE assessments
    5       9       (c )
Vacation pay
    38       36       (d )
Rate CNP under recovery
    31       18       (e )
Natural disaster reserve
    51       38       (e )
Fuel-hedging assets
    9       6       (f )
Other assets
    13       13       (e )
Asset retirement obligations
    (139 )     (159 )     (a )
Other cost of removal obligations
    (600 )     (597 )     (a )
Deferred income tax credits
    (102 )     (148 )     (a )
Deferred purchased power
    (19 )     (19 )     (e )
Mine reclamation and remediation
    (16 )     (25 )     (e )
Fuel-hedging liabilities
    (38 )     (10 )     (f )
Other liabilities
    (11 )     (1 )     (e )
         
Total
  $ (287 )   $ (413 )        
         
 
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)   Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2006.
 
(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.
Nuclear Fuel Disposal Costs
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. Construction of an on-site dry spent fuel storage facility at Plant Farley was completed in 2005 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 has been paid over a 15 year period; the final installment is scheduled to occur in 2006. 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, 2005 under this law to be approximately $5 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 life of the related property.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

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NOTES (continued)
Alabama Power Company 2005 Annual Report
     The Company’s property, plant, and equipment consisted of the following at December 31 (in millions):
                 
    2005   2004
     
Generation
  $ 7,971     $ 7,635  
Transmission
    2,205       2,097  
Distribution
    4,115       3,922  
General
    1,000       969  
Plant acquisition adjustment
    9       9  
 
Total plant in service
  $ 15,300     $ 14,632  
 
     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 2005, the Company accrued $28 million and paid $19.7 million for an outage at Unit 2. At December 31, 2005, the reserve balance totaled $7.5 million and is included in the balance sheet in other regulatory liabilities.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2005, 3.0 percent in 2004, and 3.1 percent in 2003. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama 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.
Asset Retirement Obligations and Other Costs of Removal
Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which 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 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. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in 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 or Interpretation No. 47.
     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, 2005 was $467 million. See “Nuclear Decommissioning” herein for further information. In addition, the Company recognized asset retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, the Company recognized additional asset retirement obligations (and assets) of $35 million, related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. The Company has also identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. 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 Interpretation No. 47 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.

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Alabama Power Company 2005 Annual Report
     Details of the asset retirement obligations included in the balance sheets are as follows:
                 
    2005   2004
     
    (in millions)
Balance beginning of year
  $ 384     $ 359  
Liabilities incurred
    36        
Liabilities settled
           
Accretion
    26       25  
Cash flow revisions
           
 
Balance end of year
  $ 446     $ 384  
 
     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $417 million.
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 external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds 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). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:
                         
    Unrealized   Unrealized    
2005   Gains   Losses   Fair Value
 
    (in millions)
Equity
  $ 78.9     $ (7.7 )   $ 275.3  
Debt
    1.3       (1.6 )     106.1  
Other
    17.0             85.6  
 
Total
  $ 97.2     $ (9.3 )   $ 467.0  
 
                         
    Unrealized   Unrealized    
2004   Gains   Losses   Fair Value
 
    (in millions)
Equity
  $ 71.3     $ (4.3 )   $ 258.1  
Debt
    3.2       (0.6 )     95.5  
Other
    13.6       (0.2 )     92.0  
 
Total
  $ 88.1     $ (5.1 )   $ 445.6  
 
     The contractual maturities of debt securities at December 31, 2005 are as follows: $14.1 million in 2006; $55.2 million in 2007-2010; $27.1 million in 2011-2015; and $8.3 million thereafter.
     Sales of the securities held in the trust funds resulted in proceeds of $223.8 million, $249.0 million, and $330.0 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $9.9 million, $7.5 million and $(1.7) million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and do not represent any impairment of the underlying investments.
     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 designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2005, the accumulated provisions for decommissioning were as follows:
         
    (in millions)
External trust funds, at fair value
  $ 467  
Internal reserves
    28  
 
Total
  $ 495  
 
     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 performed in 2003 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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Alabama Power Company 2005 Annual Report
     All of the Company’s decommissioning costs for ratemaking are based on the site study. 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. Another significant assumption used was the change in the operating license for Plant Farley.
     In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved the Company’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with the NRC and other applicable requirements. The approved suspension does not affect the transfer of internal reserves (less than $1 million annually) previously collected from customers prior to the establishment of the external trust.
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 8.8 percent in 2005, 8.6 percent in 2004, and 9.0 percent in 2003. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 5.0 percent in 2005, 4.2 percent in 2004, and 3.5 percent in 2003.
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 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 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.
Natural Disaster Reserve
In accordance with an Alabama PSC order, the Company has established a natural disaster reserve (NDR) to cover the cost of uninsured damages from major storms to transmission and distribution facilities. The Company may collect a monthly NDR charge per account that consists of two components beginning January 1, 2006. The first component is intended to establish and maintain a reserve for future storms and is an on-going part of customer billing. This plan has a target reserve balance of $75 million that could be achieved in five years. The second component of the NDR charge is intended to allow recovery of the deferred Hurricanes Dennis- and Katrina-related operation and maintenance costs and to set in place a mechanism to replenish the natural disaster reserve should any future storms deplete the natural disaster reserve. The Alabama PSC order gives the Company authority to have a negative NDR balance when costs of uninsured storm damage exceed any established NDR balance. This second component allows for the recovery of a negative balance over a 24-month period. The maximum total NDR charge consisting of both components is $10 per month per account for non-residential customers and $5 per month per account for residential customers.
     As revenue from the natural disaster reserve charge is recognized, an equal amount of operation and maintenance expense related to the natural disaster reserve will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.
Environmental Cost Recovery
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

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Alabama Power Company 2005 Annual Report
annually. See Note 3 under “Retail Regulatory Matters – Rate Adjustment Procedures” for additional information.
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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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.
For pro forma purposes, Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on earnings is as follows:
                         
    As   Options   Pro
Net Income   Reported   Impact   Forma
 
    (in thousands)
2005
  $ 507,895     $ (2,829 )   $ 505,066  
2004
    481,171       (2,575 )     478,596  
2003
    472,810       (2,762 )     470,048  
 
     The estimated fair values of stock options granted in 2005, 2004, and 2003 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:
                         
    2005   2004   2003
 
Interest rate
    3.9 %     3.1 %     2.7 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.9 %     19.6 %     23.6 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
 
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 or are recoverable through the Alabama PSC approved fuel-hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges 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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Alabama Power Company 2005 Annual Report
     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:
               
2005
  $ 4,416     $ 4,403  
2004
    4,389       4,454  
 
     The fair values were based on either closing market price or closing price of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, 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
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information. However, 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 in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.
Investments
The Company maintains an investment in a debt security that matures in 2018 and is classified as available-for-sale. This security is included in the balance sheets under Other Property and Investments-Other and totaled $4.4 million and $4.8 million at December 31, 2005 and 2004, respectively. Because the interest rate resets weekly, the carrying value approximates the fair market value.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. 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, 2006, postretirement trust contributions are expected to total approximately $24.9 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 $1.3 billion in 2005 and $1.2 billion in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
                 
    Projected
    Benefit Obligations
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 1,325     $ 1,200  
Service cost
    33       30  
Interest cost
    74       71  
Benefits paid
    (65 )     (64 )
Plan amendments
    8       1  
Actuarial (gain) loss
    46       87  
 
Balance at end of year
  $ 1,421     $ 1,325  
 
                 
    Plan Assets
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 1,676     $ 1,583  
Actual return on plan assets
    262       157  
Employer contributions
    4       4  
Benefits paid
    (67 )     (68 )
 
Balance at end of year
  $ 1,875     $ 1,676  
 
     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $1.3 billion and $85 million, respectively. All plan assets are related to the qualified plan.

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Alabama Power Company 2005 Annual Report
     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   2005   2004
 
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
                 
    2005   2004
 
    (in millions)
Funded status
  $ 454     $ 351  
Unrecognized prior service cost
    79       80  
Unrecognized net (gain) loss
    (52 )     27  
 
Prepaid pension asset, net
  $ 481     $ 458  
 
     The prepaid pension asset, net is reflected in the balance sheets in the following line items:
                 
    2005   2004
 
    (in millions)
Prepaid pension asset
  $ 515     $ 489  
Employee benefit obligations
    (67 )     (60 )
Intangible asset
    10       10  
Accumulated other comprehensive income
    23       19  
 
Prepaid pension asset, net
  $ 481     $ 458  
 
     Components of the pension plans’ net periodic cost were as follows:
                         
    2005   2004   2003
 
    (in millions)
Service cost
  $ 33     $ 30     $ 27  
Interest cost
    74       71       68  
Expected return on plan assets
    (139 )     (138 )     (138 )
Recognized net (gain) loss
    2       (3 )     (12 )
Net amortization
    9       4       3  
 
Net pension cost (income)
  $ (21 )   $ (36 )   $ (52 )
 
     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, 2005, estimated benefit payments were as follows:
         
    Benefit
    Payments
    (in millions)
 
2006
  $ 65.2  
2007
    66.6  
2008
    68.4  
2009
    70.6  
2010
    73.6  
2011 to 2015
  $ 429.2  
 
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
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 465     $ 441  
Service cost
    7       7  
Interest cost
    26       24  
Benefits paid
    (21 )     (18 )
Actuarial (gain) loss
    13       11  
 
Balance at end of year
  $ 490     $ 465  
 
                 
    Plan Assets
    2005   2004
 
    (in millions)
Balance at beginning of year
  $ 212     $ 186  
Actual return on plan assets
    28       24  
Employer contributions
    26       20  
Benefits paid
    (21 )     (18 )
 
Balance at end of year
  $ 245     $ 212  
 
     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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Alabama Power Company 2005 Annual Report
                         
    Plan Assets
    Target   2005   2004
 
Domestic equity
    49 %     53 %     46 %
International equity
    11       11       13  
Fixed income
    29       28       33  
Real estate
    7       6       5  
Private equity
    4       2       3  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
                 
    2005   2004
 
    (in millions)
Funded status
  $ (245 )   $ (253 )
Unrecognized transition obligation
    29       33  
Unrecognized prior service cost
    64       68  
Unrecognized net loss (gain)
    85       87  
Fourth quarter contributions
    12       9  
 
Accrued liability recognized in the balance sheets
  $ (55 )   $ (56 )
 
     Components of the postretirement plans’ net periodic cost were as follows:
                         
    2005   2004   2003
 
    (in millions)
Service cost
  $ 7     $ 7     $ 6  
Interest cost
    26       24       25  
Expected return on plan assets
    (16 )     (18 )     (17 )
Net amortization
    11       9       9  
 
Net postretirement cost
  $ 28     $ 22     $ 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 (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 and for the year ended December 31, 2005 by approximately $3.2 million and $8.7 million, respectively, and is expected to have a similar impact on future expenses.
     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)
2006
  $ 24.5     $ (2.6 )   $ 21.9  
2007
    25.6       (3.1 )     22.5  
2008
    27.8       (3.5 )     24.3  
2009
    30.4       (3.8 )     26.6  
2010
    32.9       (4.1 )     28.8  
2011 to 2015
  $ 180.2     $ (27.7 )   $ 152.5  
 
Actuarial Assumptions
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:
                         
    2005   2004   2003
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00       3.50       3.75  
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, 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, 2005 as follows:
                 
    1 Percent   1 Percent
    Increase   Decrease
 
    (in millions)
Benefit obligation
  $ 40     $ 35  
Service and interest costs
    3       2  
 
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $14 million, $13 million, and $12 million, respectively.

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Alabama Power Company 2005 Annual Report
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. 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 such as opacity and other air quality standards, 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 pending or potential litigation against the Company cannot be predicted at this time; however, for proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company’s financial statements.
Environmental 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 Northern District of Georgia granted the Company’s motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, the Company and the EPA are currently participating in mediation with respect to the EPA’s claims.
      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.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.

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      In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The 15-month refund period will end on October 19, 2006. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
      The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are subject to refund to the extent the FERC orders any changes to the IIC.
      The Company believes that there is no meritorious basis for these allegations and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 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. These proceedings are still pending at the FERC. The Company has also received similar requests from other entities totaling approximately $7 million. The Company has opposed all such requests. 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.
Retail Regulatory Matters
The following retail ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.
Rate RSE
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. Prior to January 2007, 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. On October 4, 2005, the Alabama PSC approved a revision to

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Rate RSE. Effective January 2007 and thereafter Rate RSE adjustments are made based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0 percent per year and any annual adjustment is limited to 5.0 percent. The range of return on common equity, on which such adjustments are based, remains unchanged. If the Company’s actual return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. In conjunction with the Alabama PSC approval of a rate mechanism to recover retail costs associated with environmental laws and regulations in October 2004, the Company agreed to a moratorium on retail rate increases under Rate RSE through 2006. See “Rate CNP” herein for additional information.
Rate CNP
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). In October 2004, the Alabama PSC approved a request by the Company to amend Rate CNP to provide for the recovery of retail costs associated with environmental laws and regulations. Environmental costs to be recovered include operation and maintenance expenses, depreciation and a return on invested capital. This component of Rate CNP began operation in January 2005.
      To recover certificated purchased power costs under Rate CNP, increases of 2.6 percent in retail rates, or $79 million annually were effective July 2003 and 0.8 percent in retail rates, or $25 million annually were effective July 2004 for certificated purchase power cost. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. In April 2006, an annual true-up adjustment to Rate CNP is expected to increase retail rates by approximately 0.5 percent, or $19 million annually.
      The retail rates associated with the recovery of retail costs associated with environmental laws and regulations under Rate CNP are adjusted annually in January. Retail rates increased approximately 1.0 percent in 2005, or $33 million and approximately 1.2 percent in 2006, or $43 million.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Alabama PSC. The Company can change the retail energy cost recovery rate after submitting to the Alabama PSC an estimate of future energy costs and the current over or under recovered balance. In response to such a request, the Alabama PSC may conduct a public hearing prior to its ruling. Alternatively, the retail energy cost recovery rates requested by the Company will become effective 45 days after the initial request.
      In December 2005, the Alabama PSC approved the Company’s request to increase the retail energy cost recovery rate to 2.400 cents per kilowatt-hour, effective with billings beginning January 1, 2006.
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 NDR 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 and December 2005, the Company requested and received Alabama PSC approval of an accounting order that allowed the Company to immediately return certain regulatory liabilities to the retail customers. These orders also allowed the Company to simultaneously recover from customers an accrual of approximately $48 million to primarily offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effects of these orders had no impact on the Company’s net income in 2005.
      On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.

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      In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately $28 million). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately $30 million). The NDR balance at December 31, 2005 was a regulatory asset of $50.6 million.
      In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24 month period. The maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.
      As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.
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 $90 million in 2005, $86 million in 2004, and $87 million in 2003 and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method.
      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 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, 2005, the capitalization of SEGCO consisted of $60 million of equity and $89 million of debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $7.7 million in 2005, $12.0 million in 2004, and $2.3 million in 2003, 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 coal-fired generating plants at December 31, 2005 is as follows:
                 
    Total        
    Megawatt     Company  
Facility (Type)   Capacity     Ownership  
Greene County
    500       60.00% (1)
Plant Miller
               
Units 1 and 2
    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
  $ 115     $ 60  
Plant Miller
               
Units 1 and 2
    940       374  
 
At December 31, 2005, the Company’s Plant Miller portion of construction work in progress was $4.4 million.

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      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 combined income tax returns for the State of Georgia and the State of Alabama. Under a joint consolidated income tax allocation agreement, 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. At December 31, 2005 and 2004, the Company had $20.4 million and $21.4 million in accumulated deferred income taxes and $2.0 million and $2.3 million in accrued taxes – income taxes, respectively, payable to these subsidiaries, on the balance sheets.
      At December 31, 2005, the Company’s tax-related regulatory assets and liabilities were $389 million and $102 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to taxes applicable to capitalized interest, and to deferred taxes previously recognized at rates different than the current enacted tax law. These liabilities are primarily attributable to unamortized investment tax credits.
      Details of the income tax provisions are as follows:
                         
    2005   2004   2003
    (in millions)
Federal—
                       
Current
  $ 151     $ 44     $ 111  
Deferred
    81       219       137  
 
 
    232       263       248  
 
State —
                       
Current
    27       16       26  
Deferred
    26       34       16  
 
 
    53       50       42  
 
Total
  $ 285     $ 313     $ 290  
 
      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:
                 
    2005   2004
    (in millions)
Deferred tax liabilities:
               
Accelerated depreciation
  $ 1,626     $ 1,524  
Property basis differences
    440       416  
Premium on reacquired debt
    42       45  
Pensions
    148       136  
Fuel clause under recovered
    138       48  
Storm reserve
    26       20  
Other
    46       36  
 
Total
    2,466       2,225  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    114       112  
State effect of federal deferred taxes
    87       110  
Unbilled revenue
    22       22  
Pension and other benefits
    20       16  
Other comprehensive losses
    19       16  
Other
    69       36  
 
Total
    331       312  
 
Total deferred tax liabilities, net
    2,135       1,913  
Portion included in current (liabilities) assets, net
    (64 )     (28 )
 
Accumulated deferred income taxes in the balance sheets
  $ 2,071     $ 1,885  
 
      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 $8.8 million in 2005, $11 million in 2004, and $11 million in 2003. At December 31, 2005, 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:
                         
    2005   2004   2003
     
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    4.2       4.0       3.5  
Non-deductible book depreciation
    1.1       1.1       1.2  
Differences in prior years’ deferred and current tax rates
    (4.1 )     (0.8 )     (0.9 )
Other
    (1.3 )     (1.0 )     (1.6 )
 
Effective income tax rate
    34.9 %     38.3 %     37.2 %
 
     In accordance with Alabama PSC orders, the Company returned approximately $30 million of excess deferred income taxes to its ratepayers in 2005, resulting in causing 3.6 percent of the “Difference in prior years’ deferred and current tax rates” in the table above. See Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Cost Recovery” for additional information.
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 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, 2005, 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 had 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). 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 were recognized as operating revenues and the discount was amortized to other interest expense as scheduled capacity was 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 was payable on such bonds unless and until a default by the Company occurred. As the liquidated damages declined, a portion of the bond equal to the decrease was returned to the Company. At December 31, 2005, the bonds that were previously held in escrow were returned to the Company due to the fulfillment of the contract obligation.
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 $92.8 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.
Senior Notes
The Company issued a total of $250 million of unsecured senior notes in 2005. The proceeds of these issues were used to repay short-term indebtedness, and for other general corporate purposes.
     At December 31, 2005 and 2004, the Company had $3.6 billion and $3.5 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $246 million at December 31, 2005.

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Securities Due Within One Year
At December 31, 2005 and 2004, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $547 million and $225 million respectively.
     Debt serial maturities through 2010 applicable to total long-term debt are as follows: $547 million in 2006; $669 million in 2007; $410 million in 2008; $250 million in 2009; and $100 million in 2010.
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 $878 million (including $563 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $428 million will expire at various times during 2006. $251 million of the credit facilities expiring in 2006 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, 2005, 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 and uncommitted credit arrangements. As of December 31, 2005, the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement. As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding. During 2005, the peak amount outstanding for short-term borrowings was $315 million and the average amount outstanding was $31 million. The average annual interest rate on short-term borrowings in 2005 was 4.04 percent. Short-term borrowings are included in notes payable in the balance sheets.
     At December 31, 2005, the Company had regulatory approval to have outstanding up to $1.4 billion of short-term borrowings.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005, 2004, and 2003.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 29,044  
Net income
    (66 )
 
Total fair value
  $ 28,978  
 
     The fair value gain or loss for 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 up to and including 2008.
     The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted

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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, 2005, the Company had $1.3 billion notional amount of interest rate swaps outstanding with net fair value gains of $25.3 million as follows:
                         
    Weighted Average           Fair
    Fixed           Value
    Rate   Notional   Gain/
Maturity   Paid   Amount   (Loss)
 
            (in millions)
2006
    1.89     $ 195     $ 2.5  
2007
    2.01 *     536       7.3  
2016
    4.82       300       3.0  
2016
    4.42       300       12.5  
 
*   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 2005, 2004, and 2003, the Company settled gains (losses) of $(21.4) million, $5.5 million and $(8.0) 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 2005, 2004 and 2003, approximately $3.5 million, $(6.3) million, and $(11.3) million, respectively, of pre-tax gains/(losses) were reclassified from other comprehensive income to interest expense. For 2006, pre-tax gains of approximately $9.4 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2016 and has gains/losses that are being amortized through 2035.
7.   COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $0.9 billion in 2006, $1.1 billion in 2007, and $1.1 billion in 2008. These amounts include $18 million, $11 million, and $9 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments” herein. The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, 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.
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 provide 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 $263 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2005, the remaining balance was approximately $181 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.

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Alabama Power Company 2005 Annual Report
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, 2005 were as follows:
                         
    Commitments
            Non-    
Year   Affiliated   Affiliated   Total
     
    (in millions)
2006
  $ 50     $ 37     $ 87  
2007
    50       38       88  
2008
    50       39       89  
2009
    50       40       90  
2010
    12       23       35  
2011 and thereafter
          2       2  
 
Total commitments
  $ 212     $ 179     $ 391  
 
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 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, 2005. Total estimated minimum long-term commitments at December 31, 2005 were as follows:
                         
    Natural           Nuclear
Year   Gas   Coal   Fuel
     
    (in millions)
2006
  $ 545     $ 1,065     $ 18  
2007
    269       1,027       11  
2008
    145       524       9  
2009
    26       442       3  
2010
    19       422       6  
2011 and thereafter
    89       324       26  
 
Total commitments
  $ 1,093     $ 3,804     $ 73  
 
     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 $27.3 million in 2005, $28.3 million in 2004, and $29.5 million in 2003. Of these amounts, $17.8 million, $16.3 million, and $19.4 million for 2005, 2004, and 2003, respectively, relates to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2005, estimated minimum rental commitments for noncancellable operating leases were as follows:
                         
    Rail   Vehicles    
Year   Cars   & Other   Total
 
    (in millions)
2006
  $ 16.2     $ 7.4     $ 23.6  
2007
    8.9       6.1       15.0  
2008
    8.6       4.9       13.5  
2009
    4.8       4.6       9.4  
2010
    3.5       4.1       7.6  
2011 and thereafter
    24.0       5.1       29.1  
 
Total minimum payments
  $ 66.0     $ 32.2     $ 98.2  
 
     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 $20 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 eliminate the Company’s payments under the residual value obligations.
     Guarantees
     At December 31, 2005, the Company had outstanding guarantees related to SEGCO’s purchase of certain

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Alabama Power Company 2005 Annual Report
pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets as described above in “Operating Leases.”
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, 2005, 1,106 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 2003 to 2005 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, 2002
    5,693,923     $ 19.72  
Options granted
    1,201,469       27.98  
Options canceled
    (6,726 )     23.11  
Options exercised
    (1,043,013 )     16.16  
 
Balance at December 31, 2003
    5,845,653       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
    5,758,137       24.42  
Options granted
    1,180,491       32.70  
Options canceled
    (1,973 )     30.10  
Options exercised
    (1,708,670 )     21.95  
 
Balance at December 31, 2005
    5,227,985     $ 27.09  
 
 
               
 
Options exercisable:
               
At December 31, 2003
    3,171,383          
At December 31, 2004
    3,404,264          
At December 31, 2005
    2,943,134          
 
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price
    Range of Options
    13-21   21-28   28-35
 
Outstanding:
                       
Shares (in thousands)
    700       2,266       2,262  
Average remaining life (in years)
    4.3       6.3       8.6  
Average exercise price
  $ 17.30     $ 26.05     $ 31.17  
Exercisable:
                       
Shares (in thousands)
    700       1,897       346  
Average exercise price
  $ 17.30     $ 25.68     $ 29.59  
 
9.   NUCLEAR INSURANCE
Under the Price-Anderson Amendment Act (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 $10.8 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 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 $30 million to be paid for each incident in any one year.
     The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
     Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 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

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NOTES (continued)
Alabama Power Company 2005 Annual Report
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 $41 million.
     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, 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, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property claims stemming from terrorism within a 12 month duration, is $3.2 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.
     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 2005 and 2004 are as follows:
                         
                    Net Income
                    After
                    Dividends
Quarter   Operating   Operating   on Preferred
Ended   Revenues   Income   Stock
    (in millions)
March 2005
  $ 970     $ 157     $ 93  
June 2005
    1,086       253       122  
September 2005
    1,458       443       236  
December 2005
    1,134       161       57  
 
                       
March 2004
  $ 960     $ 202     $ 91  
June 2004
    1,059       239       104  
September 2004
    1,246       415       220  
December 2004
    971       164       66  
 
     The Company’s business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Alabama Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands)
  $ 4,647,824     $ 4,235,991     $ 3,960,161     $ 3,710,533     $ 3,586,390  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 507,895     $ 481,171     $ 472,810     $ 461,355     $ 386,729  
Cash Dividends on Common Stock (in thousands)
  $ 409,900     $ 437,300     $ 430,200     $ 431,000     $ 393,900  
Return on Average Common Equity (percent)
    13.72       13.53       13.75       13.80       11.89  
Total Assets (in thousands)
  $ 13,689,907     $ 12,781,525     $ 12,099,575     $ 11,591,666     $ 11,303,605  
Gross Property Additions (in thousands)
  $ 890,062     $ 786,298     $ 661,154     $ 645,262     $ 635,540  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 3,792,726     $ 3,610,204     $ 3,500,660     $ 3,377,740     $ 3,310,877  
Preferred stock
    465,046       465,047       372,512       247,512       317,512  
Mandatorily redeemable preferred securities
                300,000       300,000       347,000  
Long-term debt payable to affiliated trusts
    309,279       309,279                    
Long-term debt
    3,560,186       3,855,257       3,377,148       2,872,609       3,742,346  
 
Total (excluding amounts due within one year)
  $ 8,127,237     $ 8,239,787     $ 7,550,320     $ 6,797,861     $ 7,717,735  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    46.7       43.8       46.4       49.7       42.9  
Preferred stock
    5.7       5.6       4.9       3.6       4.1  
Mandatorily redeemable preferred securities
                4.0       4.4       4.5  
Long-term debt payable to affiliated trusts
    3.8       3.8                    
Long-term debt
    43.8       46.8       44.7       42.3       48.5  
 
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
  AA-     AA-       A+       A+       A+  
Preferred Stock —
                                       
Moody’s
  Baa1     Baa1     Baa1     Baa1     Baa1  
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
    1,184,406       1,170,814       1,160,129       1,148,645       1,139,542  
Commercial
    212,546       208,547       204,561       203,017       196,617  
Industrial
    5,492       5,260       5,032       4,874       4,728  
Other
    759       753       757       789       751  
 
Total
    1,403,203       1,385,374       1,370,479       1,357,325       1,341,638  
 
Employees (year-end)
    6,621       6,745       6,730       6,715       6,706  
 

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Alabama Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands) :
                                       
Residential
  $ 1,476,211     $ 1,346,669     $ 1,276,800     $ 1,264,431     $ 1,138,499  
Commercial
    1,062,341       980,771       913,697       882,669       829,760  
Industrial
    1,065,124       948,528       844,538       788,037       763,934  
Other
    17,745       16,860       16,428       16,080       15,480  
 
Total retail
    3,621,421       3,292,828       3,051,463       2,951,217       2,747,673  
Sales for resale — non-affiliates
    551,408       483,839       487,456       474,291       485,974  
Sales for resale — affiliates
    288,956       308,312       277,287       188,163       245,189  
 
Total revenues from sales of electricity
    4,461,785       4,084,979       3,816,206       3,613,671       3,478,836  
Other revenues
    186,039       151,012       143,955       96,862       107,554  
 
Total
  $ 4,647,824     $ 4,235,991     $ 3,960,161     $ 3,710,533     $ 3,586,390  
 
Kilowatt-Hour Sales (in thousands) :
                                       
Residential
    18,073,783       17,368,321       16,959,566       17,402,645       15,880,971  
Commercial
    14,061,650       13,822,926       13,451,757       13,362,631       12,798,711  
Industrial
    23,349,769       22,854,399       21,593,519       21,102,568       20,460,022  
Other
    198,715       198,253       203,178       205,346       198,102  
 
Total retail
    55,683,917       54,243,899       52,208,020       52,073,190       49,337,806  
Sales for resale — non-affiliates
    15,442,728       15,483,420       17,085,376       15,553,545       15,277,839  
Sales for resale — affiliates
    5,735,429       7,233,880       9,422,301       8,844,050       8,843,094  
 
Total
    76,862,074       76,961,199       78,715,697       76,470,785       73,458,739  
 
Average Revenue Per Kilowatt-Hour (cents) :
                                       
Residential
    8.17       7.75       7.53       7.27       7.17  
Commercial
    7.55       7.10       6.79       6.61       6.48  
Industrial
    4.56       4.15       3.91       3.73       3.73  
Total retail
    6.50       6.07       5.84       5.67       5.57  
Sales for resale
    3.97       3.49       2.88       2.72       3.03  
Total sales
    5.80       5.31       4.85       4.73       4.74  
Residential Average Annual Kilowatt-Hour Use Per Customer
    15,347       14,894       14,688       15,198       13,981  
Residential Average Annual Revenue Per Customer
  $ 1,253     $ 1,155     $ 1,106     $ 1,104     $ 1,002  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    12,216       12,216       12,174       12,153       12,153  
Maximum Peak-Hour Demand (megawatts) :
                                       
Winter
    9,812       9,556       10,409       9,423       9,300  
Summer
    11,162       10,938       10,462       10,910       10,241  
Annual Load Factor (percent)
    63.2       63.2       64.1       62.9       62.5  
Plant Availability (percent) :
                                       
Fossil-steam
    90.5       87.8       85.9       85.8       87.1  
Nuclear
    92.9       88.7       94.7       93.2       83.7  
 
Source of Energy Supply (percent) :
                                       
Coal
    59.5       56.5       56.5       55.5       56.8  
Nuclear
    17.2       16.4       17.0       17.1       15.8  
Hydro
    5.6       5.6       7.0       5.1       5.1  
Gas
    6.8       8.9       7.6       11.6       10.7  
Purchased power —
                                       
From non-affiliates
    3.8       5.4       4.1       4.0       4.4  
From affiliates
    7.1       7.2       7.8       6.7       7.2  
 
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 (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, 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, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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-152 to II-184) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power Company 2005 Annual Report
OVERVIEW
Business Activities
Georgia 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 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 rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and fuel prices. In December 2004, the Company completed a major retail rate proceeding that is expected to provide earnings stability (2004 Retail Rate Plan). This regulatory action also enables the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and continued environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future. The Company expects further rate proceedings in 2006 to address fuel cost recovery due to higher than expected fuel costs for coal and natural gas.
     On December 13, 2005, the Company and Savannah Electric and Power Company (Savannah Electric) entered into a merger agreement, under which Savannah Electric will merge into the Company, with the Company continuing as the surviving corporation (the Merger). The Merger must be approved by Savannah Electric’s preferred shareholders and is subject to receipt of certain regulatory approvals from the Federal Energy Regulatory Commission (FERC), the Georgia Public Service Commission (PSC), and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to be completed by July 2006. See FUTURE EARNINGS POTENTIAL – “Merger” and Note 3 to the financial statements under “Retail Regulatory Matters – Merger” for additional information.
Key Performance Indicators
In striving to maximize shareholder value while providing low-cost energy to more than two million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. 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 customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro 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. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.
     The Company’s 2005 results compared to its targets for some of these indicators are reflected in the following chart.
         
Key
Performance Indicator
  2005
Target Performance
  2005
Actual Performance
Customer Satisfaction   Top quartile in customer surveys   Top quartile
Peak Season EFOR   2.75% or less   1.42%
Net Income   $678 million   $715 million
     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the focus that management places on these indicators, as well as the commitment shown by the employees in achieving or exceeding management’s expectations.
Earnings
The Company’s 2005 earnings totaled $715 million representing a $57 million (8.7 percent) increase over 2004. Operating income increased in 2005 due to higher base retail revenues resulting from the retail rate increase

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effective January 1, 2005 and more favorable weather, as well as higher wholesale revenues resulting from new contracts effective January 1, 2005, partially offset by increased non-fuel operating expenses. 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 resulting from a Georgia PSC three-year retail rate plan approved in 2001 (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 despite lower base retail revenues resulting from the extremely mild summer weather. Higher wholesale revenues and lower non-fuel operating expenses contributed to the 2003 increase.
RESULTS OF OPERATIONS
A condensed income statement for the Company is as follows:
                                 
            Increase (Decrease)
    Amount   From Prior Year
    2005   2005   2004   2003
    (in millions)
 
Operating revenues
  $ 6,634     $ 1,263     $ 457     $ 92  
Fuel
    1,831       598       128       101  
Purchased power
    1,170       194       200       92  
Other operation and maintenance
    1,481       81       153       (78 )
Depreciation and amortization
    504       229       (74 )     (54 )
Taxes other than income taxes
    260       32       15       11  
 
Total operating expenses
    5,246       1,134       422       72  
 
Operating income
    1,388       129       35       20  
Total other income and (expense)
    (241 )     (20 )     5       2  
Income taxes
    431       52       13       9  
 
Net income
    716       57       27       13  
Dividends on preferred stock
    1                    
 
Net income after dividends on preferred stock
  $ 715     $ 57     $ 27     $ 13  
 
Revenues
Operating revenues in 2005, 2004, and 2003 and the percent of change from the prior year are as follows:
                         
    Amount
    2005   2004   2003
    (in millions)
Retail – prior year
  $ 4,777     $ 4,310     $ 4,288  
Change in -
                       
Base rates
    195              
Sales growth
    135       151       30  
Weather
    21       32       (66 )
Fuel cost recovery and other
    515       284       58  
 
Retail – current year
  $ 5,643       4,777       4,310  
 
Sales for resale -
                       
Non-affiliates
    519       247       260  
Affiliates
    265       166       175  
 
Total sales for resale
    784       413       435  
 
Other operating revenues
    207       181       169  
 
Total operating revenues
  $ 6,634     $ 5,371     $ 4,914  
 
Percent change
    23.5 %     9.3 %     1.9 %
 
     Retail base revenues of $3.6 billion in 2005 increased by $351 million (10.9 percent) from 2004 primarily due to the retail rate increase effective January 1, 2005, sustained economic strength, customer growth, more favorable weather, and generally higher prices to large business customers. See Note 3 to the financial statements under “Retail Regulatory Matters – Rate Plans” for additional information. 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 and the sluggish economy.
     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. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.

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     Wholesale revenues from sales to non-affiliated utilities were:
                         
    2005     2004     2003  
    (in millions)  
Unit power sales —
                       
Capacity
  $ 33     $ 31     $ 34  
Energy
    31       33       31  
Other power sales —
                       
Capacity and other
    155       75       93  
Energy
    300       108       102  
 
Total
  $ 519     $ 247     $ 260  
 
     Revenues from unit power sales contracts remained relatively constant in 2005 and 2004. Revenues from unit power sales contracts decreased slightly in 2003 due to decreased energy sales. Revenues from other non-affiliated sales increased $272 million (148.6 percent) in 2005 and decreased $12 million (6.2 percent) and $8 million (3.9 percent) in 2004 and 2003, respectively. The increase in 2005 is due to new contracts with thirty electric membership corporation customers that went into effect in January 2005 which increased the demand for energy. The capacity component of these transactions increased $73.2 million in 2005 over 2004.
     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 Intercompany Interchange Contract (IIC), as approved by the FERC. In 2005, kilowatt-hour (KWH) energy sales to affiliates increased 1.5 percent due to higher demand, while the increase in associated revenues was 59.4 percent due to higher fuel prices. In 2004, 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 $25.7 million (14.2 percent) in 2005 from 2004 primarily due to higher transmission revenues of $16 million related to work performed for the other owners of the integrated transmission system in the State of Georgia and higher revenues under the open access tariff agreement, higher outdoor lighting revenues of $5.4 million, and higher customer fees that went into effect in January 2005 of $5.9 million. Other operating revenues increased $11.7 million (6.9 percent) in 2004 over 2003 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 from the prior year 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.
Energy Sales
KWH sales for 2005 and the percent change by year were as follows:
                                 
    KWH   Percent Change
    2005   2005   2004   2003
    (in billions)
Residential
    23.6       2.9 %     5.3 %     (1.7 )%
Commercial
    29.8       6.3       4.0       (0.1 )
Industrial
    25.0       (5.0 )     2.5       (0.1 )
Other
    0.6       (0.1 )     1.1       0.4  
 
                               
Total retail
    79.0       1.4       3.8       (0.5 )
 
                               
Sales for resale -
                               
Non-affiliates
    11.2       88.2       (32.5 )     9.5  
Affiliates
    4.9       1.5       (18.2 )     47.5  
 
                               
Total sales for resale
    16.1       49.6       (26.8 )     22.0  
 
                               
Total sales
    95.1       7.2       (1.2 )     2.6  
 
     Residential KWH sales increased 2.9 percent in 2005 over 2004 due to more favorable weather, customer growth of 1.7 percent, and a 1.1 percent increase in the average energy consumption per customer. Commercial KWH sales increased 6.3 percent due to more favorable weather, sustained economic strength, customer growth of 1.8 percent, and a reclassification of customers from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC when compared

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to 2004. Industrial sales decreased 5.0 percent primarily due to this reclassification of customers.
     Residential KWH sales increased 5.3 percent in 2004 from 2003 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 from 2002 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. Average retail sales growth assuming normal weather is expected to be 2.1 percent from 2006 to 2010.
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 system load, 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 KWH generated, and the average cost of purchased power per net KWH were as follows:
                         
    2005   2004   2003
     
Total generation (billions of KWH)
    80.5       71.5       73.1  
Sources of generation (percent) —
                       
Coal
    75.3       75.4       75.4  
Nuclear
    18.6       22.5       21.6  
Hydro
    2.4       2.0       2.7  
Oil and gas
    3.7       0.1       0.3  
Average cost of fuel per net KWH generated (cents) —
    2.04       1.55       1.46  
Average cost of purchased power per net KWH (cents) —
    7.25       5.17       4.03  
 
     Fuel expense increased 48.5 percent in 2005 from the prior year primarily due to an increase in the average cost of fuel, particularly natural gas, and a 12.3 percent increase in generation to meet higher demand. Fuel expense increased 11.6 percent in 2004 over 2003 primarily due to an increase in the average cost of coal and natural gas. Fuel expense increased 10.1 percent in 2003 over 2002 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.
     Purchased power expense increased $194 million (19.9 percent) in 2005, $200 million (25.9 percent) in 2004, and $92 million (13.3 percent) in 2003. These increases are primarily the result of new purchased power agreements (PPAs) between the Company and Southern Power that went into effect in each of 2004, 2003, and 2002. Additional capacity expenses associated with these PPAs were $30 million, $65 million, and $75 million in 2005, 2004, and 2003, respectively. The increases in purchased power expenses also reflect the impact of the significant increases in fuel costs discussed previously.
     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 increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2005 and 2004 hurricanes, result in an immediate market response; however, the long-term 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
In 2005, other operations and maintenance expenses increased $81 million (5.8 percent). Maintenance for generating plant and transmission and distribution increased $23.5 million and $13.9 million, respectively, as a result of scheduled outages and, to a lesser extent, certain flexible projects planned for other periods. Increased employee benefit expense of $18.4 million related to pension and medical benefits and higher property insurance costs of $5.3 million resulting from storm damage also contributed to the increase. Customer

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assistance expense and uncollectible account expense also increased an additional $9.3 million in 2005 over 2004, primarily as a result of promotional expenses related to an energy efficiency program and an increased number of customer bankruptcies, respectively. In 2004, other operations 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 operations 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.
     Depreciation and amortization increased $229 million (83 percent) in 2005 over 2004 primarily due to the expiration at the end of 2004 of certain provisions of the Company’s 2001 Retail Rate Plan. In accordance with the 2001 Retail Rate Plan, the Company amortized an accelerated cost recovery liability as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates evenly over the three years ended December 31, 2004. This treatment resulted in a credit to amortization expense of $187.1 million in 2004 and a total decrease in depreciation and amortization of $74 million and $54 million in 2004 and 2003, respectively. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.
     Taxes other than income taxes increased $32 million (14.1 percent) primarily due to higher municipal gross receipts taxes of $18.1 million resulting from increased operating revenues and higher property taxes of $14.0 million. 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.
Other Income and (Expense)
Allowance for equity funds used during construction remained relatively constant in 2005 and increased $15.9 million in 2004, primarily due to the construction of the McIntosh combined cycle Units 10 and 11 which were placed in service in June 2005.
     Interest income remained relatively constant in 2005. 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 expense increased $38.8 million (21.3 percent) in 2005 from 2004 primarily due to the issuance of additional senior notes in 2005 and generally higher interest rates on variable rate debt and commercial paper. 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. The Company refinanced or retired $635 million, $400 million, and $665 million of securities in 2005, 2004, and 2003, respectively. Interest capitalized increased in 2005 and 2004 due to the Plant McIntosh construction referenced above and decreased in 2003 due to the transfer of a project to Southern Power in 2002.
     Other income and (expense), net increased $17.1 million in 2005 from 2004 primarily due to $14.2 million of additional gas hedge gains. Other income and (expense), net decreased in 2004 primarily due to the $13 million disallowance of Plant McIntosh construction costs in December 2004, 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 statements under “Retail Regulatory Matters – Fuel Hedging Program” and “Plant McIntosh Construction Project” 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-

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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 utility providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. 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 PPAs, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and revenues are reviewed and adjusted periodically. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” and “FERC Matters” 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 the Company’s 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 of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, 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.
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 and Alabama Power, alleging that the Company and Alabama Power had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to certain coal-fired generating facilities. Through subsequent amendments and other legal proceedings, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities, including the Company’s Plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against the Company and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions.”
     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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and

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methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Georgia’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.
Plant Wansley Environmental Litigation
In December 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. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted the Company’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. 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. 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
General
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. Applicable statutes 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 these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $1.2 billion in

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capital projects to comply with these requirements, with annual costs of $117.4 million, $47.4 million, and $105.7 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures could exceed an additional $3.3 billion to assure compliance with existing and new regulations, including $410 million, $674.6 million, and $515.8 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $787.9 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2 and NOx emissions, maintain compliance with existing regulations, and to meet new requirements.
     Approximately $699.8 million of these expenditures are related to reducing NOx emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NOx reduction rules. Although the State of Georgia was originally included in the states subject to the regional NOx rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NOx reduction rules for Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of the State of Georgia’s state implementation plan.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. Areas within the Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Macon (Georgia) and a 20-county area within metropolitan Atlanta. State implementation plans, including new emission control regulations necessary to bring those areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NOx emissions from power plants.
     During 2005, the EPA’s fine particulate matter “nonattainment” designations became effective for several areas within the Company’s service area in Georgia, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. The EPA has also published proposed revisions to lower the level of particulate matter currently allowed.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks

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and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clear Air Mercury Rule on the Company, will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clear Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2 , NOx , and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.
     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 and two others are scheduled for completion in 2008. The total estimated cost of these projects is $173 million, with $85 million remaining to be spent. The Company is also conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.
     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by the State of Georgia, and therefore, cannot be determined at this time
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release 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.

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     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account related to certain environmental insurance settlements. Under the 2004 Retail Rate Plan, this regulatory liability is being amortized as a credit to expense over a three-year period that began January 1, 2005. However, the Georgia PSC also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures are being charged against the resulting reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010-2012. The Company is continuing to evaluate future energy and emissions profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $4.9 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $10.9 million, of which $3.2 million relates to sales inside the retail service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this

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matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC also initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and Southern Company Services, Inc., as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding discussed herein under “PSC Matters – Plant McIntosh Construction Project”, be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, 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 all such requests, 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.
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.
PSC Matters
Merger
In connection with the Merger, the Company and Savannah Electric plan to establish a coastal regional organization for the Company that will be operating following completion of the Merger. Management expects that current Savannah Electric employees will fill most of the positions in the new regional organization.

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     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, the Company and Savannah Electric filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, the Company and Savannah Electric are seeking the approval of the Georgia PSC with respect to the following matters:
  the transfer of Savannah Electric’s generating facilities and certification of the generating facilities as the Company’s assets;
  amendments to the Company’s Integrated Resource Plan to add the current Savannah Electric’s customers and generating facilities;
  the transfer of Savannah Electric’s assigned service territory to the Company;
  adoption of the Company’s service rules and regulations to the current Savannah Electric customers;
  new fuel rate and base rate schedules that would apply to the Company’s sale of electricity to the current Savannah Electric customers;
  adoption of a “merger transition adjustment” rate that would be used to more closely align Savannah Electric’s existing base rates to those of the Company and a “merger transition credit” rate that would credit the additional revenues collected from former Savannah Electric customers to the Company’s existing customers; and
  the issuance of additional shares of the Company’s common stock to Southern Company in exchange for Southern Company’s shares of Savannah Electric common stock.
     The Company has also requested the Georgia PSC to better align the rates for Savannah Electric’s customers with those of the Company. Currently, Savannah Electric customers pay slightly lower base rates and significantly higher fuel rates than the Company’s customers. The overall effect is that Savannah Electric customers pay substantially higher overall costs for electricity. See “Fuel Cost Recovery” herein for additional information.
Rate Plans
In December 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 are being evaluated annually against a retail return on common equity (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 were increased by approximately $194 million and customer fees were increased by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operation and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability. In 2005 the Company recorded $2.7 million revenue subject to refund for estimated earnings above 12.25 percent retail ROE.
     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. Until then, the Company will not file for a general base rate increase unless its projected retail ROE falls below 10.25 percent. However, in connection with the Merger, the Company has requested Georgia PSC approval of a “merger transition adjustment” that would be used to adjust Savannah Electric’s existing base rates to more closely match the existing base rates for the Company. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate Plans” 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 for capacity from Plant McIntosh Units 10 and 11, construction of which was 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 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.

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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. See “FERC Matters — Intercompany Interchange Contract” above for additional information.
     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 reflected an approximate $16 million disallowance, of which $13 million was attributable to the Company, and reduced the Company’s 2004 net income by approximately $8 million. The Georgia PSC also certified a total completion cost of $547 million for the project. In June 2005, Plant McIntosh Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. 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 Regulatory Matters — Rate Plans” and “Plant McIntosh Construction Project” for additional information.
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 natural gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets herein.
     In May 2005, the Georgia PSC approved the Company’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructed that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, the Company would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with the Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. The Company has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, the Company and Savannah Electric will file a combined request in March 2006 to increase the Company’s fuel cost recovery rate.
     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Company and Savannah Electric generating fleet as well as the under recovered fuel balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all of the Company’s customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.
     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of the Company’s fuel practices was initiated. The Company and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.
     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable cost and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow.
Nuclear
As part of a potential expansion of Plant Vogtle, the Company and Southern Nuclear have notified the Nuclear Regulatory Commission (NRC) of their intent to apply for an early site permit (ESP) this year and a combined construction and operating license (COL) in 2008. In addition, a reactor design from Westinghouse Electric Company has been selected and a purchase agreement is being negotiated. Participation agreements have been reached with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. At this point, no final decision has

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been made regarding actual construction. The NRC’s streamlined licensing process for new nuclear units allows utilities to seek regulatory approval at various stages. These stages include design certification, which is obtained by the reactor vendor, and the ESP and COL, which are each obtained by the owner-operators of the units. An ESP indicates site approval is obtained before a company decides to build and the COL provides regulatory approval for building and operating the plant. In addition, any generation by the Company must be certified by the Georgia PSC.
     Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy plans to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs, then to choose one of the applications and file it for NRC review and approval. The COL ultimately is expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.
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 $21 million, $35 million, and $54 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $47 million, $44 million, and $41 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. 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.
     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. Management has reviewed and discussed critical accounting policies and estimates 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, 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.

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Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. 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 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
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47, Conditional Asset Retirement Obligations (FIN 47), which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”
     At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $91 million. The adoption of FIN 47 did not have any effect on the Company’s income statement.

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Stock Options
On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition continued to be stable at December 31, 2005 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 increased $56 million resulting primarily from increased retail operating revenues (see RESULTS OF OPERATIONS herein), partially offset by the increase in under recovered deferred fuel costs.
     Fuel costs are generally recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.
     In 2005, gross utility plant additions were $906 million. These additions were primarily related to Plant McIntosh Units 10 and 11, transmission and distribution facilities, 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 48.3 percent in 2005, 47.7 percent in 2004, and 48.3 percent in 2003. 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 from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.
     The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by the Company is subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended, on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission 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. 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 the Company are not commingled with funds of any other company.
     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 credit arrangements with banks totaling $780 million, of which $778 million was unused, at the beginning of 2006. 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 retail operating companies.

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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, 2005, the Company had outstanding $268 million of commercial paper and no extendible commercial notes.
     At the beginning of 2006, bank credit arrangements were as follows:
                                 
            Expires  
Total   Unused     2006     2007     2010  
            (in millions)  
$780
  $ 778     $ 70     $ 350     $ 360  
     The credit arrangements that expire in 2006 allow for the execution of term loans for an additional two-year period.
Financing Activities
During 2005, the Company issued $810 million of long-term debt. The issuances were used to refund $635 million of long-term debt and to fund the Company’s ongoing construction program.
     Subsequent to December 31, 2005, the Company redeemed all of its outstanding preferred stock at a redemption price of $107 per share.
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, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $6 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $245 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 risk management activities. At December 31, 2005, 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 rate 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 including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis.
     To mitigate future exposure to changes in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. These swaps have a notional amount of $300 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on outstanding variable long-term debt that has not been hedged at January 1, 2006 was 3.56 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 $3.3 million at January 1, 2006. 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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report
value of changes in energy-related derivative contracts and year-end valuations were as follows at December 31:
                 
    Changes in Fair Value
    2005   2004
    (in millions)
Contracts beginning of year
  $ 5.8     $ 3.2  
Contracts realized or settled
    (40.0 )     (12.2 )
Current period changes (a)
    60.8       14.8  
 
Contracts end of year
  $ 26.6     $ 5.8  
 
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2005 Year-End Valuation Prices
    Total   Maturity
    Fair Value   Year 1   1-3 Years
    (in millions)
Actively quoted
  $ 26.8     $ 16.4     $ 10.4  
External sources
    (0.2 )     (0.2 )      
 
Contracts end of year
  $ 26.6     $ 16.2     $ 10.4  
 
     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. Of the net gains, the Company is allowed to retain 25 percent in earnings. In 2005, the Company had a total net gain of $64.1 million, of which the Company retained $16.0 million. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Hedging Program” for additional information. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in millions)
Regulatory liabilities, net
  $ 26.7  
Net income
    (0.1 )
 
Total fair value
  $ 26.6  
 
     Unrealized gains (losses) recognized in income in 2005, 2004, and 2003 were not material. The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $1.3 billion for 2006, $1.4 billion for 2007, and $1.3 billion for 2008. Environmental expenditures included in these amounts are $410 million, $674.6 million, and $515.8 million for 2006, 2007, and 2008, 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.
     As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also as discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal 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, redemption of preferred stock, 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)
Georgia Power Company 2005 Annual Report
     Amounts in the following chart exclude any effects on the Company of the Merger.
Contractual Obligations
                                         
            2007-     2009-     After        
    2006     2008     2010     2010     Total  
                    (in millions)                  
Long-term debt (a)
                                       
Principal
  $ 153     $ 306     $ 282     $ 4,563     $ 5,304  
Interest
    265       496       468       4,989       6,218  
Preferred stock
    15                         15  
Commodity derivative obligations(b)
    12                         12  
Operating leases
    34       58       44       58       194  
Purchase commitments(c)
                                       
Capital (d)
    1,251       2,738       2,421             6,410  
Coal
    1,579       2,220       694       40       4,533  
Nuclear fuel
    44       42       25       64       175  
Natural gas(e)
    577       525       511       2,047       3,660  
Purchased power
    343       689       559       994       2,585  
Long-term service agreements
    7       18       24       144       193  
Trusts(f)
                                       
Nuclear decommissioning
    7       14       14       117       152  
Postretirement benefits
    18       41                   59  
DOE assessments
    4                         4  
 
Total
  $ 4,309     $ 7,147     $ 5,042     $ 13,016     $ 29,514  
 
 
(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, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest risk.
 
(b)   For additional information see Notes 1 and 6 to the financial statements herein.
 
(c)   The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $1.5 billion, $1.4 billion, and $1.2 billion, respectively.
 
(d)   The Company forecasts capital expenditures over a five-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, 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, 2005.
 
(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 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)
Georgia Power Company 2005 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, storm cost recovery and repairs, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and the Company, the impacts of the adoption of new accounting rules, 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 implementation of the Energy Policy Act of 2005, 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 FERC matters and 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, including rate cases related to fuel cost recovery;
  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 Securities and Exchange Commission.
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, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report
                         
 
    2005     2004     2003  
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 5,642,812     $ 4,776,985     $ 4,309,972  
Sales for resale—
                       
Non-affiliates
    519,673       246,545       259,376  
Affiliates
    264,989       166,245       174,855  
Other revenues
    206,729       181,033       169,304  
 
Total operating revenues
    6,634,203       5,370,808       4,913,507  
 
Operating Expenses:
                       
Fuel
    1,830,829       1,232,496       1,103,963  
Purchased power—
                       
Non-affiliates
    408,563       304,978       258,621  
Affiliates
    761,466       671,098       516,944  
Other operations
    949,722       902,167       827,972  
Maintenance
    531,168       498,114       419,206  
Depreciation and amortization
    504,248       275,488       349,984  
Taxes other than income taxes
    259,825       227,806       212,827  
 
Total operating expenses
    5,245,821       4,112,147       3,689,517  
 
Operating Income
    1,388,382       1,258,661       1,223,990  
 
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    26,808       26,659       10,752  
Interest income
    6,281       6,657       15,625  
Interest expense, net of amounts capitalized
    (221,199 )     (182,370 )     (182,583 )
Interest expense to affiliate trusts
    (59,510 )     (44,565 )      
Distributions on mandatorily redeemable preferred securities
          (15,839 )     (59,675 )
Other income (expense), net
    5,742       (11,362 )     (10,551 )
 
Total other income and (expense)
    (241,878 )     (220,820 )     (226,432 )
 
Earnings Before Income Taxes
    1,146,504       1,037,841       997,558  
Income taxes
    430,812       379,170       366,311  
 
Net Income
    715,692       658,671       631,247  
Dividends on Preferred Stock
    693       670       670  
 
Net Income After Dividends on Preferred Stock
  $ 714,999     $ 658,001     $ 630,577  
 
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, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report
                         
 
    2005     2004     2003  
    (in thousands)  
Operating Activities:
                       
Net income
  $ 715,692     $ 658,671     $ 631,247  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    592,264       361,958       424,321  
Deferred income taxes and investment tax credits, net
    231,708       251,623       199,265  
Deferred expenses - affiliates
    1,268       (10,563 )     (7,399 )
Allowance for equity funds used during construction
    (26,808 )     (26,659 )     (10,752 )
Pension, postretirement, and other employee benefits
    (19,468 )     (15,868 )     (30,225 )
Tax benefit of stock options
    15,711       9,701       11,649  
Other, net
    (11,068 )     (19,764 )     18,929  
Changes in certain current assets and liabilities —
                       
Receivables
    (591,498 )     (227,204 )     (4,395 )
Fossil fuel stock
    2,528       (46,730 )     (17,490 )
Materials and supplies
    (53,942 )     618       (7,677 )
Prepaid income taxes
    (43,626 )     14,358       (3,951 )
Other current assets
    4,108       (23,672 )     1,599  
Accounts payable
    110,118       132,001       (62,553 )
Accrued taxes
    85,098       (64,563 )     52,348  
Accrued compensation
    3,822       (6,664 )     (3,111 )
Other current liabilities
    33,289       5,836       19,845  
 
Net cash provided from operating activities
    1,049,196       993,079       1,211,650  
 
Investing Activities:
                       
Property additions
    (842,870 )     (741,151 )     (717,993 )
Nuclear decommissioning trust fund purchases
    (381,235 )     (541,048 )     (656,806 )
Nuclear decommissioning trust fund sales
    372,536       532,349       648,107  
Purchase of property from affiliates
          (339,750 )     (2 )
Cost of removal net of salvage
    (29,428 )     (21,756 )     (28,265 )
Change in construction payables, net of joint owner portion
    4,037       413       (32,223 )
Other
    (315 )     (4,961 )     1,008  
 
Net cash used for investing activities
    (877,275 )     (1,115,904 )     (786,174 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    59,509       70,956       (220,400 )
Proceeds—
                       
Senior notes
    625,000       600,000       1,000,000  
Pollution control bonds
    185,000              
Mandatorily redeemable preferred securities
          200,000        
Capital contributions from parent company
    149,034       260,068       40,809  
Redemptions—
                       
Pollution control bonds
    (185,000 )            
Senior notes
    (450,000 )     (200,000 )     (665,000 )
Mandatorily redeemable preferred securities
          (200,000 )      
Payment of preferred stock dividends
    (546 )     (654 )     (696 )
Payment of common stock dividends
    (556,100 )     (565,500 )     (565,800 )
Other
    (21,679 )     (17,247 )     (22,563 )
 
Net cash provided from (used for) financing activities
    (194,782 )     147,623       (433,650 )
 
Net Change in Cash and Cash Equivalents
    (22,861 )     24,798       (8,174 )
Cash and Cash Equivalents at Beginning of Year
    33,497       8,699       16,873  
 
Cash and Cash Equivalents at End of Year
  $ 10,636     $ 33,497     $ 8,699  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for—
                       
Interest (net of $10,871, $8,920, and $5,428 capitalized, respectively)
  $ 250,445     $ 228,190     $ 215,463  
Income taxes (net of refunds)
    207,973       127,115       145,048  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Georgia Power Company 2005 Annual Report
                 
 
Assets   2005     2004  
    (in thousands)
Current Assets:
               
Cash and cash equivalents
  $ 10,636     $ 33,497  
Receivables—
               
Customer accounts receivable
    418,154       317,937  
Unbilled revenues
    141,875       140,027  
Under recovered regulatory clause revenues
    454,683       345,542  
Other accounts and notes receivable
    110,397       94,377  
Affiliated companies
    84,597       17,042  
Accumulated provision for uncollectible accounts
    (8,647 )     (7,100 )
Fossil fuel stock, at average cost
    181,739       184,267  
Vacation pay
    59,190       57,372  
Materials and supplies, at average cost
    323,908       270,422  
Prepaid expenses
    70,825       32,695  
Other
    50,248       28,262  
 
Total current assets
    1,897,605       1,514,340  
 
Property, Plant, and Equipment:
               
In service
    19,603,249       18,681,533  
Less accumulated provision for depreciation
    7,575,926       7,217,607  
 
 
    12,027,323       11,463,926  
Nuclear fuel, at amortized cost
    134,798       124,745  
Construction work in progress
    563,155       766,140  
 
Total property, plant, and equipment
    12,725,276       12,354,811  
 
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    68,188       66,192  
Nuclear decommissioning trusts, at fair value
    486,591       459,194  
Other
    71,468       64,571  
 
Total other property and investments
    626,247       589,957  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    500,882       505,664  
Prepaid pension costs
    476,458       450,270  
Deferred under recovered regulatory clause revenues
    295,116        
Other regulatory assets
    330,483       246,462  
Other
    195,716       160,834  
 
Total deferred charges and other assets
    1,798,655       1,363,230  
 
Total Assets
  $ 17,047,783     $ 15,822,338  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Georgia Power Company 2005 Annual Report
                 
 
Liabilities and Stockholder’s Equity   2005     2004  
    (in thousands)
 
Current Liabilities:
               
Securities due within one year
  $ 167,317     $ 452,498  
Notes payable
    267,743       208,233  
Accounts payable —
               
Affiliated
    285,019       194,253  
Other
    360,455       310,763  
Customer deposits
    129,293       115,661  
Accrued taxes —
               
Income taxes
    150,896       78,269  
Other
    204,778       129,520  
Accrued interest
    88,885       74,529  
Accrued vacation pay
    45,602       44,894  
Accrued compensation
    137,303       127,340  
Other
    120,312       83,632  
 
Total current liabilities
    1,957,603       1,819,592  
 
Long-term Debt (See accompanying statements)
    4,179,218       3,709,852  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    969,073       969,073  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,730,303       2,556,040  
Deferred credits related to income taxes
    158,759       170,973  
Accumulated deferred investment tax credits
    287,726       300,018  
Employee benefit obligations
    358,137       331,002  
Asset retirement obligations
    627,465       504,515  
Other cost of removal obligations
    404,614       411,692  
Other regulatory liabilities
    97,015       84,678  
Other
    63,335       59,733  
 
Total deferred credits and other liabilities
    4,727,354       4,418,651  
 
Total Liabilities
    11,833,248       10,917,168  
 
Preferred Stock (See accompanying statements)
          14,609  
 
Common Stockholder’s Equity (See accompanying statements)
    5,214,535       4,890,561  
 
Total Liabilities and Stockholder’s Equity
  $ 17,047,783     $ 15,822,338  
 
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, 2005 and 2004
Georgia Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
    (in thousands)     (percent of total)  
Long-Term Debt:
                               
Long-term notes payable —
                               
5.50% due December 1, 2005
  $     $ 150,000                  
Variable rate (1.66% to 1.96% at 1/1/05) due 2005
          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       125,000                  
Variable rate (4.53% at 1/1/06) due 2009
    150,000       150,000                  
4.00% to 6.00% due 2011-2045
    1,850,000       1,225,000                  
 
Total long-term notes payable
    2,575,000       2,400,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds — non-collateralized:
                               
2.83% to 5.45% due 2012-2034
    812,560       812,560                  
Variable rate (2.82% to 3.08% at 1/1/06) due 2011-2032
    873,330       873,330                  
 
Total other long-term debt
    1,685,890       1,685,890                  
 
Capitalized lease obligations
    74,484       76,982                  
 
Unamortized debt premium (discount), net
    (3,448 )     (522 )                
 
Total long-term debt (annual interest requirement — $205.5 million)
    4,331,926       4,162,350                  
Less amount due within one year
    152,708       452,498                  
 
Long-term debt excluding amount due within one year
    4,179,218       3,709,852       40.3 %     38.7 %
 
Long-term Debt Payable to Affiliated Trusts:
                               
4.88% to 7.13% due 2042 (annual interest requirement — $59.5 million)
    969,073       969,073       9.4       10.1  
 
Cumulative Preferred Stock:
                               
$100 stated value at 4.60%
                               
Authorized — 5,000,000 shares
                               
Outstanding — 145,689 shares (annual dividend requirement — $0.7 million)
    14,609       14,609                  
 
Less amount due within one year
    14,609                        
 
Total cumulative preferred stock excluding amount due within one year
          14,609       0.0       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
    2,643,012       2,478,268                  
Retained earnings
    2,261,698       2,102,798                  
Accumulated other comprehensive income (loss)
    (34,425 )     (34,755 )                
 
Total common stockholder’s equity
    5,214,535       4,890,561       50.3       51.0  
 
Total Capitalization
  $ 10,362,826     $ 9,584,095       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, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report
                                         
                            Other    
    Common   Paid-In   Retained   Comprehensive    
    Stock   Capital   Earnings   Income (loss)   Total
                    (in thousands)                
 
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  
Net income after dividends on preferred stock
                714,999             714,999  
Capital contributions from parent company
          164,745                   164,745  
Other comprehensive income (loss)
                      330       330  
Cash dividends on common stock
                (556,100 )           (556,100 )
Other
          (1 )     1              
 
Balance at December 31, 2005
  $ 344,250     $ 2,643,012     $ 2,261,698     $ (34,425 )   $ 5,214,535  
 
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report
                         
    2005   2004   2003
    (in thousands)
         
Net income after dividends on preferred stock
  $ 714,999     $ 658,001     $ 630,577  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(1,981), $(3,861) and $(5,133), respectively
    (3,140 )     (6,122 )     (8,138 )
Change in fair value of marketable securities, net of tax of $317 and $(114)
    501       (181 )      
Changes in fair value of qualifying hedges, net of tax of $1,214, $(5,046) and $(3,241), respectively
    1,925       (7,999 )     (5,550 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $848, $1,528 and $1,208, respectively
    1,044       2,421       2,217  
 
Total other comprehensive income (loss)
    330       (11,881 )     (11,471 )
 
Comprehensive Income
  $ 715,329     $ 646,120     $ 619,106  
 
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2005 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 Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies — Alabama Power, the Company, Gulf Power, Mississippi Power, and Savannah Electric — provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power — related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC). 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 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. In January 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
     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 to current year presentation.
     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. 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.
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 $330 million in 2005, $292 million in 2004, and $303 million in 2003. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the PUHCA 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 $328 million in 2005, $311 million in 2004, and $289 million in 2003.
     The Company has an agreement with Southern Power under which the Company operates and maintains Southern Power owned plants Dahlberg, Franklin, and Wansley at cost. Billings under these agreements with Southern Power amounted to $5.2 million in 2005, $4.8 million in 2004, and $5.3 million in 2003.

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NOTES (continued)
Georgia Power Company 2005 Annual Report
     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 $7.3 million in 2005, $7.7 million in 2004, and $7.4 million in 2003.
     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 $61 million in 2005, $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 $216 million in 2005, $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. Expenses associated with these PPAs were $419 million, $282 million, and $203 million in 2005, 2004, and 2003, respectively. Additionally, the Company recorded a reduction of $1 million and an increase of $11 million of prepaid capacity expenses included on the balance sheets at December 31, 2005 and 2004, 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 $4.3 million in 2005, $6.8 million in 2004, and $4.9 million in 2003. 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 $5.5 million in 2005, $3.3 million in 2004, and $3.7 million in 2003. See Note 4 for additional information.
     The Company provides incidental services to other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in the last two years, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, has caused an increase in these activities. The total amount of storm assistance provided to Alabama Power, Gulf Power, and Mississippi Power in 2005 was $4.1 million, $4.4 million, and $55 million, respectively. The total amount of storm assistance provided to Alabama Power and Gulf Power in 2004 was $4.1 million and $6.4 million, respectively. These activities were billed at cost.
     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, and Southern Power 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.
     The Company has entered into an agreement to merge with Savannah Electric. See Note 3 under “Retail Regulatory Matters – Merger” for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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NOTES (continued)
Georgia Power Company 2005 Annual Report
     Regulatory assets and (liabilities) reflected in the Company’s balance sheets at December 31 relate to the following:
                         
    2005   2004   Note
    (in millions)
Deferred income tax charges
  $ 501     $ 506       (a )
Premium on reacquired debt
    170       177       (b )
Corporate building lease
    52       53       (e )
Vacation pay
    59       57       (d )
Postretirement benefits
    18       20       (e )
DOE assessments
    6       10       (c )
Generating plant outage costs
    46       40       (g )
Other regulatory assets
    33       11       (e )
Asset retirement obligation
    65       (20 )     (a )
Other cost of removal obligations
    (404 )     (412 )     (a )
Deferred income tax credits
    (159 )     (171 )     (a )
Environmental remediation
    (19 )     (22 )     (f )
Purchased power
    (33 )           (f )
Other regulatory liabilities
    (30 )     (6 )     (e )
 
Total
  $ 305     $ 243          
 
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 2006.
 
(d)   Recorded as earned by employees and recovered as paid, generally within one year.
 
(e)   Recorded and recovered or amortized as approved by the Georgia PSC.
 
(f)   Amortized over a three-year period ending in 2007. See Note 3 under “Retail Regulatory Matters — Rate Plans.”
 
(g)   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.
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 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 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 $70 million in 2005, $73 million in 2004, and $74 million in 2003.
Nuclear Fuel Disposal Costs
The Company has contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 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 is operational and can be expanded to accommodate spent fuel through the life of the plant.
     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 has been paid over a 15-

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Georgia Power Company 2005 Annual Report
year period; the final installment is scheduled to occur in 2006. 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, 2005 under this law to be approximately $4 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 $12.5 million, $12.9 million, and $12.0 million were recorded in 2005, 2004, and 2003, respectively.
Property, Plant, and Equipment
The Company’s property, plant, and equipment consisted of the following at December 31 (in millions):
                 
    2005   2004
Generation
  $ 9,571     $ 9,002  
Transmission
    2,994       2,870  
Distribution
    5,953       5,744  
General
    1,057       1,038  
Plant acquisition adjustment
    28       28  
 
Total plant in service
  $ 19,603     $ 18,682  
 
     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 Georgia PSC rate order, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.
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 2005, 2.6 percent in 2004, and 2.7 percent in 2003. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. In connection with the new retail rate plan for the Company ending December 31, 2007 (2004 Retail Rate Plan), effective January 1, 2005, the depreciation rates were revised by the Georgia PSC. The revised depreciation rates had no material impact on the Company’s financial statements.
     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

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NOTES (continued)
Georgia Power Company 2005 Annual Report
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 in 2003. The Company recorded a credit to amortization expense of $77 million in 2004. See Note 3 under “Retail Regulatory Matters — Rate Plans” 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. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations (FIN 47), which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of their retirements was dependent on future events. The Company has received approval from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations 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 or FIN 47.
     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, 2005 was $487 million. In addition, the Company has recognized retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The Company also recorded additional asset retirement obligations (and assets) of approximately $91 million related to asbestos removal. 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 assets 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 allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. 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:
                 
    2005   2004
    (in millions)
Balance beginning of year
  $ 505     $ 476  
Liabilities incurred
    91        
Liabilities settled
    (2 )     (2 )
Accretion
    33       31  
 
Balance end of year
  $ 627     $ 505  
 
     If FIN 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $591 million.
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 external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds 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). The trust funds are invested in a tax- 

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Georgia Power Company 2005 Annual Report
efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:
                         
    Unrealized   Unrealized   Fair
2005   Gains   Losses   Value
    (in millions)
Equity
  $ 76.7     $ (6.3 )   $ 325.5  
Debt
    2.8       (0.8 )     135.3  
Other
                25.8  
Total
  $ 79.5     $ (7.1 )   $ 486.6  
                         
    Unrealized   Unrealized   Fair
2004   Gains   Losses   Value
    (in millions)
Equity
  $ 68.7     $ (4.0 )   $ 308.2  
Debt
    5.3       (0.1 )     138.0  
Other
                13.0  
Total
  $ 74.0     $ (4.1 )   $ 459.2  
     The contractual maturities of debt securities at December 31, 2005 are as follows: $3.2 million in 2006; $34.9 million in 2007-2010; $32.4 million in 2011-2015; and $57.2 million thereafter.
     Sales of the securities held in the trust funds resulted in proceeds of $372.5 million, $532.3 million, and $648.1 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $12.6 million, $14.1 million, and $21.3 million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and do not represent any impairment of the underlying investments.
     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. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Georgia PSC. The amount expensed in 2005 and fund balances were as follows:
                 
    Plant   Plant
    Hatch   Vogtle
    (in millions)
Amount expensed in 2005
  $     $ 7  
Accumulated provisions:
               
External trust funds, at fair value
  $ 313     $ 174  
Internal reserves
          1  
 
Total
  $ 313     $ 175  
 
     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 performed in 2003 for the Company’s ownership interests in plants Hatch and Vogtle were as follows:
                 
    Plant   Plant
    Hatch   Vogtle
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.
     Under the 2001 Retail Rate Plan, the Georgia PSC approved the annual decommissioning costs for ratemaking of $9 million. This amount was based on the NRC generic estimate to decommission the radioactive

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Georgia Power Company 2005 Annual Report
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.
     Under the 2004 Retail Rate Plan, effective January 1, 2005, the Georgia PSC decreased the annual decommissioning costs for ratemaking 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 2005, 2004, and 2003, the average AFUDC rates were 8.02 percent, 8.22 percent, and 5.51 percent, respectively. AFUDC and interest capitalized, net of taxes, were 4.7 percent and 4.9 percent of net income after dividends on preferred stock for 2005 and 2004, respectively, and less than 3 percent for 2003.
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 Regulatory Matters” and “Plant McIntosh Construction Project” for information regarding a regulatory disallowance by the Georgia PSC in December 2004.
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. The Company accrues $6.3 million annually that is recoverable through base rates. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.
Environmental Cost Recovery
Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account related to certain environmental insurance settlements. Under the 2004 Retail Rate Plan, this regulatory liability is being 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 are charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

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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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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.
     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date.
     The pro forma impact of fair-value accounting for options granted on earnings is as follows:
                         
    As   Options   Pro
Net Income   Reported   Impact   Forma
    (in millions)
2005
  $ 715     $ (3 )   $ 712  
2004
  $ 658       (3 )   $ 655  
2003
  $ 631       (4 )   $ 627  
     The estimated fair value of stock options granted in 2005, 2004, and 2003 was derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options.
                         
    2005   2004   2003
 
Interest rate
    3.90 %     3.10 %     2.70 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.90 %     19.60 %     23.60 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
     See Note 8 for additional information.
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 or are recoverable through the Georgia PSC-approved fuel hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market

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through current period income and are recorded on a net basis in the statements of income.
     The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
     The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:
                 
    Carrying   Fair
    Amount   Value
    (in millions)
Long-term debt:
               
2005
  $ 5,227     $ 5,195  
2004
  $ 5,055     $ 5,125  
     The fair values were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of marketable securities and qualifying cash flow hedges, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, 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. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. 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, 2006, such contributions are expected to total approximately $18.4 million. The measurement date for plan assets and obligations is September 30 for each year presented.
Pension Plans
The accumulated benefit obligation for the pension plans was $1.9 billion in 2005 and $1.7 billion in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and the fair
value of plan assets was as follows:
                 
Projected Benefit Obligation
    2005   2004
    (in millions)
Balance at beginning of year
  $ 1,885     $ 1,727  
Service cost
    45       42  
Interest cost
    106       101  
Benefits paid
    (85 )     (85 )
Plan amendments
    13       1  
Actuarial loss
    91       99  
 
Balance at end of year
  $ 2,055     $ 1,885  
 
                 
    Plan Assets
    2005   2004
    (in millions)
Balance at beginning of year
  $ 2,181     $ 2,055  
Actual return on plan assets
    339       207  
Benefits paid
    (80 )     (81 )
 
Balance at end of year
  $ 2,440     $ 2,181  
 

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     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $1.945 billion and $110 million, respectively. All plan assets are related to the qualified plan.
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   2005   2004
 
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
                 
    2005   2004
    (in millions)
Funded status
  $ 385     $ 295  
Unrecognized transition amount
    (4 )     (8 )
Unrecognized prior service cost
    109       108  
Unrecognized net actuarial gain (loss)
    (54 )     21  
 
Prepaid pension asset, net
  $ 436     $ 416  
 
     The prepaid pension asset, net is reflected in the balance sheets in the following line items:
                 
    2005   2004
    (in millions)
Prepaid pension asset
  $ 476     $ 450  
Employee benefit obligations
    (96 )     (89 )
Other property and investments
    15       19  
Accumulated other comprehensive income
    41       36  
 
Prepaid pension asset, net
  $ 436     $ 416  
 
     Components of the plans’ net periodic cost were as follows:
                         
    2005   2004   2003
    (in millions)
Service cost
  $ 45     $ 42     $ 38  
Interest cost
    106       101       100  
Expected return on plan assets
    (182 )     (180 )     (179 )
Recognized net (gain)/loss
    3       (5 )     (19 )
Net amortization
    7       7       6  
 
Net pension (income)
  $ (21 )   $ (35 )   $ (54 )
 
     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, 2005, estimated benefit payments were as follows:
         
    Benefit
    Payments
    (in millions)
2006
  $ 88  
2007
    91  
2008
    94  
2009
    97  
2010
    102  
2011 to 2015
  $ 607  
     

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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
    2005   2004
    (in millions)
Balance at beginning of year
  $ 726     $ 723  
Service cost
    10       10  
Interest cost
    41       41  
Benefits paid
    (32 )     (31 )
Actuarial loss
    24       42  
Plan amendments
          (59 )
 
Balance at end of year
  $ 769     $ 726  
 
                 
    Plan Assets
    2005   2004
    (in millions)
Balance at beginning of year
  $ 299     $ 265  
Actual return on plan assets
    38       32  
Employer contributions
    40       33  
Benefits paid
    (32 )     (31 )
 
Balance at end of year
  $ 345     $ 299  
 
     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   2005   2004
 
Domestic equity
    43 %     43 %     42 %
International equity
    21       22       23  
Domestic fixed income
    19       19       19  
Global fixed income
    11       11       11  
Real estate
    4       3       3  
Private equity
    2       2       2  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
                 
    2005   2004
    (in millions)
Funded status
  $ (424 )   $ (428 )
Unrecognized transition obligation
    70       78  
Unrecognized prior service cost
    25       27  
Unrecognized net loss
    203       203  
Fourth quarter contributions
    21       15  
 
Employee benefit obligations recognized in the balance sheets
  $ (105 )   $ (105 )
 
     Components of the postretirement plans’ net periodic cost were as follows:
                         
    2005   2004   2003
    (in millions)
Service cost
  $ 10     $ 10     $ 9  
Interest cost
    41       41       40  
Expected return on plan assets
    (22 )     (25 )     (24 )
Net amortization
    18       18       16  
 
Net postretirement cost
  $ 47     $ 44     $ 41  
 
     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 and for the year ended December 31, 2005 by approximately $5 million and $10 million, respectively, and is expected to have a similar impact on future expenses.
     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)
2006
  $ 37     $ (3 )   $ 34  
2007
    39       (4 )     35  
2008
    42       (4 )     38  
2009
    46       (4 )     42  
2010
    50       (5 )     45  
2011 to 2015
    280       (34 )     246  
 
Actuarial Assumptions
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:
                         
    2005   2004   2003
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00       3.50       3.75  
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, 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, 2005, as follows:
                 
    1 Percent   1 Percent
    Increase   Decrease
    (in millions)
Benefit obligation
  $ 70     $ 62  
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 2005, 2004, and 2003 were $19 million, $18 million, and $18 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 such as opacity and other air quality standards, 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 pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, 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 and Alabama Power, alleging that the Company and Alabama Power had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to certain coal-fired generating facilities. Through subsequent amendments and other legal proceedings, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power after it was dismissed from the original action. In these lawsuits, the

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EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against the Company and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
     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.
Plant Wansley Environmental Litigation
In December 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. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted the Company’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. 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. 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 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. 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. As of December 31, 2005, 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. Additional claims for recovery of natural resource damages at the site are anticipated. The Company has also recognized $36 million in cumulative expenses through December 31, 2005 for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory.
     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.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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.

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     In December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC agreed to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $4.9 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $10.9 million, of which $3.2 million relates to sales inside the retail service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC also initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding involving an approval of PPAs between Southern Power and the Company and Savannah Electric, be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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

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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.
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 and amended to add four more plaintiffs. The lawsuit also raised claims on behalf of a purported class. The plaintiffs sought compensatory and punitive damages in an unspecified amount, as well as injunctive relief.
     Following various court decisions in favor of the defendants and subsequent appeals by the plaintiffs, on July 13, 2005, the plaintiffs filed a petition for writ of certiorari to the U.S. Supreme Court. On October 17, 2005, the petition was denied. This matter is now concluded.
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. Management believes that the Company has complied with applicable laws and that the plaintiffs’ claims are without merit.
     In January 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 appealed this ruling to the Georgia Court of Appeals. The Georgia Court of Appeals reversed, in part, the court’s order and remanded the case to the trial court for the determination of further issues. After the Court of Appeals’ decision, the plaintiffs filed a motion for reconsideration, which was denied, and a petition for certiorari to the Georgia Supreme Court, which is currently pending. 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. 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. In January 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.

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Property Tax Dispute
The Company is involved in a significant property tax dispute with Monroe County, Georgia (Monroe County). The Monroe County Board of Tax Assessors (Monroe Board) has issued assessments reflecting substantial increases in the ad valorem tax valuation of the Company’s 22.95 percent ownership interest in Plant Scherer, which is located in Monroe County, for tax years 2003, 2004, and 2005. The Company is aggressively pursuing administrative appeals in Monroe County and has filed notices of arbitration for all three years. The appeals are currently stayed, pending the outcome of the litigation discussed below.
     In November 2004, the Company filed suit, on its behalf, against the Monroe Board in the Superior Court of Monroe County. The Company contends that Monroe County acted without statutory authority in changing the valuation of a centrally assessed utility as established by the Revenue Commissioner of the State of Georgia and requests injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from the Company. On December 22, 2005, the court granted Monroe County’s motion for summary judgment. The Company has filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.
     If the Company is not successful in its administrative appeals and if Monroe County is successful in defending the litigation, the Company could be subject to total additional taxes through December 31, 2005 of up to $13 million, plus penalties and interest. The ultimate outcome of this matter cannot currently be determined.
Retail Regulatory Matters
Merger
On December 13, 2005, the Company and Savannah Electric entered into an Agreement and Plan of Merger. Savannah Electric will merge into the Company, with the Company continuing as the surviving corporation (the Merger). At the effective time of the Merger, each share of the Company’s common stock will remain issued and outstanding; each share of the Company’s preferred stock issued and outstanding will have been redeemed prior to the Merger; the issued and outstanding shares of Savannah Electric common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of the Company’s common stock; and each share of Savannah Electric preferred stock issued and outstanding immediately prior to the Merger will be converted into the right to receive one share of a new series of the Company’s Class A Preferred Stock. The Merger must be approved by the preferred shareholders of Savannah Electric and is subject to the receipt of certain regulatory approvals from the FERC, the Georgia PSC, and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to be completed by July 2006. The Merger is not expected to have a material impact on the Company’s financial statements.
     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, the Company and Savannah Electric have filed an application with the Georgia PSC with respect to certain approvals that will be necessary to effectively complete the Merger. In particular, the Company and Savannah Electric plan to seek the approval of the Georgia PSC with respect to the following matters:
  the transfer of Savannah Electric’s generating facilities and certification of the generating facilities as the Company’s assets;
 
  amendments to the Company’s Integrated Resource Plan to add the current Savannah Electric’s customers and generating facilities;
 
  the transfer of Savannah Electric’s assigned service territory to the Company;
 
  adoption of the Company’s service rules and regulations to the current Savannah Electric customers;
 
  new fuel rate and base rate schedules that would apply to the Company’s sale of electricity to the current Savannah Electric customers;
 
  adoption of a “merger transition adjustment” rate that would be used to more closely align Savannah Electric’s existing base rates to those of the Company and a “merger transition credit” rate that would credit the additional revenues collected from former Savannah Electric customers to the Company’s existing customers; and
 
  the issuance of additional shares of the Company’s common stock to Southern Company in exchange for Southern Company’s shares of Savannah Electric common stock.

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Rate Plans
Under the terms of the 2004 Retail Rate Plan, which the Georgia PSC approved in December 2004, the Company’s earnings are evaluated against a retail return on common equity (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 were 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 2005, the Company recorded $2.7 million in revenue subject to refund related to earnings in excess of 12.25 percent retail ROE.
     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. Until then, the Company may not file for a general base rate increase unless its projected retail ROE falls below 10.25 percent.
     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 ROE 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 retail ROE 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.
Fuel Hedging Program
In 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 2005, the Company had a total net gain of $64.1 million, of which the Company retained $16 million.
Fuel Cost Recovery
On May 17, 2005, the Georgia PSC approved the Company’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet. Under recovered fuel amounts for the periods subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, the Company would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with the Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. The Company has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, the Company and Savannah Electric will file a combined request in March 2006 to increase the Company’s fuel cost recovery rate.
     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Company and Savannah Electric generating fleet as well as the under recovered fuel balances existing at June 30, 2006. The new fuel cost recovery

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rate would be billed beginning in July 2006 to all of the Company’s customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.
     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of the Company’s fuel practices was initiated. The Company and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.
     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable cost and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow.
Nuclear Performance Standards
Through December 2004, the Georgia PSC had adopted a three-year performance standard for the Company’s nuclear generating units. The performance standard was based on each unit’s capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria. For the period 2002-2004, the Company’s performance fell within the criteria prescribed by the Georgia PSC; there was no associated award or penalty. Effective January 1, 2005, the Georgia PSC discontinued the nuclear performance standard.
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 was 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 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 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. See “FERC Matters – Intercompany Interchange Contract” herein for additional information.
     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 reflected an approximate $16 million disallowance, of which $13 million was attributable to the Company, and reduced the Company’s net income by approximately $8 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Units 10 and 11 were placed into service at a total cost that did not exceed the certified amount. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates evenly over the three years ending 2007. See “Retail Regulatory Matters—Rate Plans” 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,

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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:
                         
    2005   2004   2003
    (in millions)
Energy
  $ 54     $ 51     $ 55  
Capacity
    38       36       34  
 
Total
  $ 92     $ 87     $ 89  
 
     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 has contracted to operate and maintain the plants as agent for the co-owners and 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 common facilities and Plant McIntosh combined cycle units with Savannah Electric who operates the plants. The Company and Progress Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida, Inc.
     At December 31, 2005, 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 %   $ 3,311 *   $ 1,809  
Plant Hatch (nuclear)
    50.1       935       492  
Plant Wansley (coal)
    53.5       395       172  
Plant Scherer (coal)
                       
Units 1 and 2
    8.4       115       56  
Unit 3
    75.0       562       270  
Plant McIntosh CC (combined cycle)
    83.9       436       7  
Plant McIntosh Common Facilities (combustion-turbine)
    75.0       27       5  
Rocky Mountain (pumped storage)
    25.4       169 *     92  
Intercession City (combustion-turbine)
    33.3       12       2  
 
* Investment includes write-offs
     At December 31, 2005, the portion of total construction work in progress related to Plants Wansley, Scherer, and Rocky Mountain was $8.3 million, $0.5 million, and $0.1 million, respectively, primarily for environmental projects.
     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 files a consolidated federal income tax return and combined income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, 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

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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 $10 million payable to these subsidiaries in Accumulated Deferred Income Taxes on the balance sheets at December 31, 2005.
     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 remaining balance of the related deferred taxes of $5.3 million reflected in Southern Power’s future taxable income. $3.7 million of this payable to Southern Power is included in Other Deferred Credits and $1.6 million is included in Affiliated Accounts Payable in the balance sheet at December 31, 2005.
     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 $12.2 million reflected in the Company’s future taxable income. $10.8 million of this receivable from Southern Power is included in Other Deferred Debits and $1.4 million is included in Affiliated Accounts Receivable in the balance sheet at December 31, 2005.
     At December 31, 2005, tax-related regulatory assets were $501 million and tax-related regulatory liabilities were $159 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:
                         
    2005   2004   2003
    (in millions)
Total provision for income taxes:
                       
Federal:
                       
Current
  $ 173     $ 116     $ 143  
Deferred
    203       221       181  
 
 
    376       337       324  
 
State:
                       
Current
    26       12       24  
Deferred
    29       30       16  
Deferred investment tax credits
                2  
 
Total
  $ 431     $ 379     $ 366  
 
     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:
                 
    2005   2004
    (in millions)
Deferred tax liabilities:
               
Accelerated depreciation
  $ 2,177     $ 2,050  
Property basis differences
    558       577  
Employee benefit obligations
    163       149  
Fuel clause under recovery
    305       141  
Premium on reacquired debt
    69       72  
Storm damage reserve
    13       6  
Other
    74       81  
 
Total
    3,359       3,076  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    116       106  
Other property basis differences
    139       147  
Other deferred costs
    126       94  
Employee benefit obligations
    51       55  
Other comprehensive income
    23       22  
Unbilled revenue
    13       11  
Other
    33       19  
 
Total
    501       454  
 
Total deferred tax liabilities, net
    2,858       2,622  
Portion included in current (liabilities) assets, net
    (128 )     (66 )
 
Accumulated deferred income taxes in the balance sheets
  $ 2,730     $ 2,556  
 
     In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied

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as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $12 million in 2005, $12 million in 2004, and $15 million in 2003. At December 31, 2005, 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:
                         
    2005   2004   2003
     
Federal statutory rate
    35 %     35 %     35 %
State income tax, net of federal deduction
    3       3       3  
Non-deductible book depreciation
    1       1       1  
Other
    (1 )     (2 )     (2 )
 
Effective income tax rate
    38 %     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, 2005, 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.
Securities Due Within One Year
A summary of the scheduled maturities and redemptions of securities due within one year at December 31 is as follows:
                 
    2005   2004
    (in millions)
Capital lease
  $ 3     $ 2  
Senior notes
    150       450  
Preferred stock
    15        
 
Total
  $ 168     $ 452  
 
     Serial maturities through 2010 applicable to total long-term debt and preferred stock are as follows: $168 million in 2006; $303 million in 2007; $3 million in 2008; $278 million in 2009; and $4 million in 2010.
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, 2005 was $1.7 billion.
Senior Notes
The Company issued a total of $625 million of unsecured senior notes in 2005. 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, 2005 and 2004, the Company had $2.6 billion and $2.4 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company.
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, 2005 and 2004, the Company had a

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capitalized lease obligation for its corporate headquarters building of $74 million and $77 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. See Note 1 under “Regulatory Assets and Liabilities.”
Bank Credit Arrangements
At the beginning of 2006, the Company had credit arrangements with banks totaling $780 million, of which $778 million was unused. Of these facilities, $70 million expires at various times throughout 2006; $350 million expires in 2007, with the remaining $360 million expiring in 2010. The facilities that expire in 2006 provide the option of converting borrowings into a two-year term loan. The Company expects to renew its facilities, as needed, prior to expiration. The agreements contain stated borrowing rates. 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 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. At December 31, 2005, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings.
     The $778 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, 2005 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, 2005 was $268 million. The amount of commercial paper outstanding at December 31, 2004 was $208 million. There were no outstanding extendible commercial notes at December 31, 2005. Commercial paper is included in notes payable on the balance sheets.
     During 2005, the peak amount of short-term debt outstanding was $549 million and the average amount outstanding was $242 million. The average annual interest rate on short-term debt in 2005 was 3.20 percent.
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. See Note 3 under “Retail Regulatory Matters – Fuel Hedging Program” for information on the Company’s fuel hedging program. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005, 2004, and 2003.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 26,643  
Other comprehensive income
     
Net income
    (81 )
 
Total fair value
  $ 26,562  
 
     The fair value gain or loss for 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 2008.
     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

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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.
     At December 31, 2005, the Company had $1.0 billion notional amounts of interest derivatives accounted for as cash flow hedges outstanding with net fair value gains as follows:
                         
                    Fair
                    Value
    Weighted Average   Notional   Gain /
Maturity   Fixed Rate Paid   Amount   (Loss)
            (in millions)
2007
    2.67%     $ 300     $ 2.4  
2006-2007
    2.09% -3.85 %*   $ 400     $ 1.2  
2037
    4.58% -5.75 %**   $ 300     $ (1.1 )
 
*   Series of interest rate caps and collars (showing the lowest floor and highest cap) with variable rate based on one-month LIBOR
 
**   Interest rate collar
     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 2005, 2004, and 2003, the Company settled gains (losses) totaling $0.9 million, $(12.4) million, and $(11.3) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. For the years 2005, 2004, and 2003, approximately $1.9 million, $3.9 million, and $3.4 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2006, pre-tax losses of approximately $0.5 million are expected to be reclassified from other comprehensive income to interest expense. The Company has gains/losses that are being amortized through 2017.
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be approximately $1.3 billion, $1.4 billion, and $1.3 billion in 2006, 2007, and 2008, respectively. These amounts include $44 million, $28 million, and $14 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments” herein. 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, 2005, significant purchase commitments were outstanding in connection with the construction program.
     The Company completed construction of Plant McIntosh Units 10 and 11 in June 2005 and has no other generating plants currently under construction. 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, is 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 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 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 $186 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 also entered into an LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently

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estimated at $13.1 million. The contract contains cancellation provisions at the option of the Company.
     Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. Work performed by GE is capitalized or charged to expense as appropriate net of any joint owner billings, based on the nature of the work.
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 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, 2005.
     Total estimated minimum long-term obligations at December 31, 2005 were as follows:
                         
    Commitments
    Natural           Nuclear
    Gas   Coal   Fuel
    (in millions)
2006
  $ 577     $ 1,579     $ 44  
2007
    325       1,313       28  
2008
    200       907       14  
2009
    257       422       11  
2010
    254       272       14  
2011 and thereafter
    2,047       40       64  
 
Total
  $ 3,660     $ 4,533     $ 175  
 
     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 $54 million, $55 million, and $57 million in 2005, 2004, and 2003, respectively. The current projected Plant Vogtle capacity payments are:
         
    Capacity Payments
 
 
  (in millions)
2006
  $ 53  
2007
    52  
2008
    54  
2009
    54  
2010
    54  
2011 and thereafter
    261  
 
Total
  $ 528  
 
     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.

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     The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations under these commitments at December 31, 2005 were as follows:
                 
    Commitments
            Non-
    Affiliated   Affiliated
    (in millions)
2006
  $ 205     $ 85  
2007
    205       86  
2008
    205       87  
2009
    205       68  
2010
    112       66  
2011 and thereafter
    455       278  
 
Total
  $ 1,387     $ 670  
 
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 2005, $38 million for 2004, and $36 million for 2003.
     At December 31, 2005, estimated minimum lease payments for these noncancelable operating leases were as follows:
                         
    Minimum Lease Payments
    Rail Cars   Other   Total
     
    (in millions)
2006
  $ 17     $ 17     $ 34  
2007
    17       14       31  
2008
    16       11       27  
2009
    15       9       24  
2010
    14       6       20  
2011 and thereafter
    48       10       58  
 
Total
  $ 127     $ 67     $ 194  
 
     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 $68 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
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. Alabama Power has also guaranteed $50 million in senior notes issued by SEGCO. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations 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.
     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 the Company’s employees ranging from line management to executives. As of December 31, 2005, 1,551 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 2003 to 2005 for the options granted

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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, 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
    (6,371 )     25.99  
Options exercised
    (1,450,309 )     18.25  
 
Balance at December 31, 2004
    7,129,216       24.19  
Options granted
    1,427,618       32.71  
Options canceled
    (12,910 )     23.75  
Options exercised
    (1,838,033 )     21.23  
 
Balance at December 31, 2005
    6,705,891     $ 26.82  
 
 
               
Options exercisable:
               
At December 31, 2003
    3,956,234          
At December 31, 2004
    4,304,091          
At December 31, 2005
    3,989,722          
 
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price
    Range of Options
    13-21   21-28   28-35
 
Outstanding:
                       
Shares (in thousands)
    991       2,922       2,794  
Average remaining life (in years)
    4.2       6.0       8.5  
Average exercise price
  $ 17.25     $ 25.94     $ 31.13  
Exercisable:
                       
Shares (in thousands)
    991       2,496       503  
Average exercise price
  $ 17.25     $ 25.59     $ 29.75  
 
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments 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 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 $15 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 $30 million to be paid for each incident in any one year.
     The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.
     Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.
     NEIL also covers additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of 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. The Company purchases the maximum limit allowed by NEIL subject to ownership limitations and has elected a 12 week waiting period.
     Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $48 million.
     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance. Both companies, however, revised their policy terms on

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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, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property 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 nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.
     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 2005 and 2004 is as follows:
                         
                    Net Income
                    After
                    Dividends on
    Operating   Operating   Preferred
Quarter Ended   Revenues   Income   Stock
 
 
          (in millions)        
March 2005
  $ 1,370     $ 286     $ 142  
June 2005
    1,459       311       158  
September 2005
    2,219       626       355  
December 2005
    1,586       165       60  
 
                       
March 2004
  $ 1,199     $ 285     $ 144  
June 2004
    1,353       322       156  
September 2004
    1,582       486       287  
December 2004
    1,237       166       71  
 
     The Company’s business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Georgia Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
Operating Revenues (in thousands)
  $ 6,634,203     $ 5,370,808     $ 4,913,507     $ 4,822,460     $ 4,965,794  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 714,999     $ 658,001     $ 630,577     $ 617,629     $ 610,335  
Cash Dividends on Common Stock (in thousands)
  $ 556,100     $ 565,500     $ 565,800     $ 542,900     $ 527,300  
Return on Average Common Equity (percent)
    14.15       13.95       14.05       13.99       14.12  
Total Assets (in thousands)
  $ 17,047,783     $ 15,822,338     $ 14,850,754     $ 14,342,656     $ 14,447,973  
Gross Property Additions (in thousands)
  $ 906,248     $ 1,126,064     $ 742,810     $ 883,968     $ 1,389,751  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 5,214,535     $ 4,890,561     $ 4,540,211     $ 4,434,447     $ 4,397,485  
Preferred stock
          14,609       14,569       14,569       14,569  
Mandatorily redeemable preferred securities
                940,000       940,000       789,250  
Long-term debt payable to affiliated trusts
    969,073       969,073                    
Long-term debt
    4,179,218       3,709,852       3,762,333       3,109,619       2,961,726  
 
Total (excluding amounts due within one year)
  $ 10,362,826     $ 9,584,095     $ 9,257,113     $ 8,498,635     $ 8,163,030  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    50.3       51.0       49.0       52.2       53.9  
Preferred stock
          0.2       0.2       0.2       0.2  
Mandatorily redeemable preferred securities
                10.2       11.1       9.6  
Long-term debt payable to affiliated trusts
    9.4       10.1                    
Long-term debt
    40.3       38.7       40.6       36.5       36.3  
 
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   Baa1
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
    1,832,520       1,801,426       1,768,662       1,734,430       1,698,407  
Commercial
    270,373       265,543       258,276       250,993       244,674  
Industrial
    8,206       7,676       7,899       8,240       8,046  
Other
    3,536       3,482       3,434       3,328       3,239  
 
Total
    2,114,635       2,078,127       2,038,271       1,996,991       1,954,366  
 
Employees (year-end)
    8,713       8,731       8,714       8,837       9,048  
 
N/A = Not Applicable.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Georgia Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
Operating Revenues (in thousands):
                                       
Residential
  $ 2,024,204     $ 1,736,072     $ 1,583,082     $ 1,600,438     $ 1,507,031  
Commercial
    2,206,252       1,812,096       1,661,054       1,631,130       1,682,918  
Industrial
    1,351,731       1,172,936       1,012,267       1,004,288       1,106,420  
Other
    60,625       55,881       53,569       52,241       52,943  
 
Total retail
    5,642,812       4,776,985       4,309,972       4,288,097       4,349,312  
Sales for resale — non-affiliates
    519,673       246,545       259,376       270,678       366,085  
Sales for resale — affiliates
    264,989       166,245       174,855       98,323       99,411  
 
Total revenues from sales of electricity
    6,427,474       5,189,775       4,744,203       4,657,098       4,814,808  
Other revenues
    206,729       181,033       169,304       165,362       150,986  
 
Total
  $ 6,634,203     $ 5,370,808     $ 4,913,507     $ 4,822,460     $ 4,965,794  
 
Kilowatt-Hour Sales (in thousands):
                                       
Residential
    23,585,115       22,930,372       21,778,582       22,144,559       20,119,080  
Commercial
    29,768,402       28,014,357       26,940,572       26,954,922       26,493,255  
Industrial
    25,027,371       26,357,271       25,703,421       25,739,785       25,349,477  
Other
    601,330       602,202       595,742       593,202       583,007  
 
Total retail
    78,982,218       77,904,202       75,018,317       75,432,468       72,544,819  
Sales for resale — non-affiliates
    11,234,527       5,969,983       8,835,804       8,069,375       8,110,096  
Sales for resale — affiliates
    4,854,914       4,782,873       5,844,196       3,962,559       3,133,485  
 
Total
    95,071,659       88,657,058       89,698,317       87,464,402       83,788,400  
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    8.58       7.57       7.27       7.23       7.49  
Commercial
    7.41       6.47       6.17       6.05       6.35  
Industrial
    5.40       4.45       3.94       3.90       4.36  
Total retail
    7.14       6.13       5.75       5.68       6.00  
Sales for resale
    4.88       3.84       2.96       3.07       4.14  
Total sales
    6.76       5.85       5.29       5.32       5.75  
Residential Average Annual Kilowatt-Hour Use Per Customer
    12,974       12,838       12,421       12,867       11,933  
Residential Average Annual Revenue Per Customer
  $ 1,113     $ 972     $ 903     $ 930     $ 894  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    15,097       13,978       13,980       14,059       14,474  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    13,501       12,208       13,153       11,873       11,977  
Summer
    15,953       15,180       14,826       14,597       14,294  
Annual Load Factor (percent)
    59.7       61.5       61.0       60.4       61.7  
Plant Availability (percent):
                                       
Fossil-steam
    90.7       90.3       87.6       80.9       88.5  
Nuclear
    89.3       94.8       94.2       88.8       94.4  
 
Source of Energy Supply (percent):
                                       
Coal
    60.8       57.9       58.6       59.5       58.5  
Nuclear
    15.1       17.3       16.8       16.2       18.1  
Hydro
    1.9       1.5       2.1       0.9       1.1  
Oil and gas
    2.9       0.1       0.3       0.3       0.4  
Purchased power -
                                       
From non-affiliates
    5.7       7.0       7.5       6.3       7.8  
From affiliates
    13.6       16.2       14.7       16.8       14.1  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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GULF POWER COMPANY
FINANCIAL SECTION

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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 (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, 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, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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-208 to II-231) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Company 2005 Annual Report
OVERVIEW
Business Activities
Gulf Power Company (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.
     Many factors 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 achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.
     Hurricanes Dennis and Katrina hit the Gulf Coast of Florida in July 2005 and August 2005, respectively, damaging portions of the Company’s service area. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida, causing substantial damage within the Company’s service area. In February 2005, the Florida Public Service Commission (PSC) approved the recovery of the Company’s storm damage costs related to Hurricane Ivan through a two-year surcharge that began in April 2005. Later in 2005, the Florida Legislature also approved securitized financing for hurricane costs and in February 2006, the Company filed with the Florida PSC requesting permission to issue securitized bonds to recover the remaining costs of these storms and to replenish its property damage reserve. See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively for additional information.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to over 400,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. 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 customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (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. Peak Season EFOR performance was adjusted to exclude the impact of outages at Plants Crist and Smith, which were attributed to manufacturer and/or vendor defects as well as removing the effects of Hurricanes Dennis and Katrina. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected economic conditions. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2005 results compared with its targets for some of these indicators are reflected in the following chart:
         
Key   2005   2005
Performance   Target   Actual
Indicator   Performance   Performance
Customer Satisfaction   Top quartile
performance in
customer surveys
  Top quartile
Peak Season EFOR   3.00%   1.50%
Net Income   $75.0 million   $75.2 million
     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2005 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 2005 net income after dividends on preferred stock was $75.2 million, an increase of $7.0 million from the previous year. In 2004, earnings were $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. The

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increase in earnings in 2005 is due primarily to higher retail sales and lower non-fuel operating expenses, excluding expenses related to Hurricane Ivan storm damage, which are offset by revenues and do not affect earnings. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein. The decrease in earnings in 2004 was due primarily to higher operating expenses related to replenishing property damage reserves and increased expenses related to employee benefits. The improvement in earnings in 2003 was primarily due to higher operating revenues related to an increase in base rates, offset somewhat by higher operating expenses and increases in depreciation expense primarily related to the commercial operation of Plant Smith Unit 3.
RESULTS OF OPERATIONS
A condensed statement of income follows:
                                 
            Increase (Decrease)
    Amount   From Prior Year
    2005   2005      2004      2003
    (in thousands)
Operating revenues
  $ 1,083,622     $ 123,491     $ 82,434     $ 57,230  
 
Fuel
    415,789       48,634       50,652       42,643  
Purchased power
    98,397       32,500       15,740       (12,841 )
Other operation and maintenance
    249,770       20,058       19,012       10,625  
Depreciation and amortization
    85,002       2,203       477       5,308  
Taxes other than income taxes
    76,387       6,531       3,741       5,082  
 
Total operating expenses
    925,345       109,926       89,622       50,817  
 
Operating income
    158,277       13,565       (7,188 )     6,413  
Total other income and (expense)
    (37,326 )     (749 )     5,219       (706 )
Income taxes
    44,981       5,286       (1,182 )     3,733  
 
Net Income
    75,970       7,530       (787 )     1,974  
Dividends on Preferred and Preference Stock
    761       544              
 
Net Income after Dividends on Preferred and Preference Stock
  $ 75,209     $ 6,986     $ (787 )   $ 1,974  
 
Revenues
Operating revenues increased in 2005 when compared to 2004 and 2003. The following table summarizes the changes in operating revenues for the past three years:
                         
    2005   2004   2003
    (in thousands)
Retail – Prior Year
  $ 736,870     $ 699,174     $ 665,836  
Change in —
                       
Base rates
                22,000  
Sales growth
    11,568       4,896       7,040  
Weather
    (4,223 )     3,313       (6,757 )
Fuel and other cost recovery
    120,644       29,487       11,055  
 
Retail – Current Year
    864,859       736,870       699,174  
 
Sales for resale —
                       
Non-affiliates
    84,346       73,537       76,767  
Affiliates
    91,352       110,264       63,268  
 
Total sales for resale
    175,698       183,801       140,035  
Other operating revenues
    43,065       39,460       38,488  
 
Total operating revenues
  $ 1,083,622     $ 960,131     $ 877,697  
 
Percent change
    12.9 %     9.4 %     7.0 %
 
     Retail revenues increased $128.0 million, or 17.4 percent, in 2005, $37.7 million, or 5.4 percent, in 2004, and $33.3 million, or 5.0 percent, in 2003. The significant factors driving these changes are shown in the table above.
     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 petitions for recovery of projected costs including any true-up amount from prior periods, and approved rates are implemented each January. Other cost recovery also includes revenues related to the recovery of expenses related to Hurricane Ivan as approved by the Florida PSC. 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,” “Property Damage Reserve,” and “Environmental Cost Recovery” and Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery” and “– Storm Damage Cost Recovery” for additional information.

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     Sales for resale were $175.7 million in 2005, a decrease of $8.1 million, or 4.4 percent, as compared to 2004, primarily due to lower energy sales to affiliates resulting from decreases in the Company’s available generation as a result of outages at Plants Crist and Smith, which were attributed to manufacturer and/or vendor defects. 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 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 following the commercial operation of Plant Smith Unit 3. Sales to and purchases from affiliated companies 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 Intercompany Interchange Contract (IIC), 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:
                         
    2005   2004   2003
    (in thousands)
Unit Power —
                       
Capacity
  $ 20,852     $ 18,780     $ 18,598  
Energy
    33,206       29,360       30,892  
 
Total
  $ 54,058     $ 48,140     $ 49,490  
 
     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 through December 2015. See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for additional information.
     Other operating revenues increased $3.6 million, $1.0 million, and $1.4 million in 2005, 2004, and 2003, respectively, primarily due to an increase in franchise fees, which are proportional to changes in revenue.
Energy Sales
Kilowatt-hour (KWH) sales for 2005 and the percent changes by year were as follows:
                                 
    KWH   Percent Change
    2005   2005   2004   2003
    (millions)                        
Residential
    5,319       2.0 %     2.2 %     (0.8 )%
Commercial
    3,736       1.1       2.2       1.7  
Industrial
    2,161       2.3       (1.6 )     4.5  
Other
    23       0.7       0.4       4.7  
     
Total retail
    11,239       1.7       1.5       1.0  
Sales for resale
                               
Non-affiliates
    2,296       1.7       (9.9 )     16.1  
Affiliates
    1,976       (36.8 )     28.1       41.8  
     
Total
    15,511       (5.6 )     3.8       8.0  
 
     Residential sales increased 2.0 percent in 2005 primarily due to customer growth, as compared to 2004. 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.
     Commercial sales increased 1.1 percent in 2005, as compared to 2004, primarily due to customer growth. 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.
     Industrial sales increased 2.3 percent in 2005, as compared to 2004, primarily due to additional sales to customers with gas-fired cogeneration resulting from high natural gas prices. 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

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sales to customers with gas-fired cogeneration resulting from high natural gas prices.
     Total energy sales to retail customers are projected to increase at a compound average growth rate of 1.8 percent during the period 2006 through 2010 due to customer growth, assuming normal weather conditions.
     Sales for resale to non-affiliates increased 1.7 percent in 2005, decreased 9.9 percent in 2004, and increased 16.1 percent in 2003, each as compared to the prior year primarily as a result of fluctuations in the fuel cost to produce energy sold to non-affiliated 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. The fluctuations in sales have a minimal effect on earnings because the energy is generally sold at variable cost.
Expenses
Total operating expenses increased $109.9 million, or 13.5 percent, in 2005, $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.
Fuel and Purchased Power
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 $48.6 million, or 13.2 percent, in 2005, $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 demand for energy and higher average costs of fuel.
     The amount and sources of generation, the average cost of fuel per net KWH generated, and the average costs of purchased power were as follows:
                         
    2005   2004   2003
Total generation (millions of KWH)
    15,024       15,841       14,988  
Sources of generation (percent) —
                       
Coal
    86       84       87  
Gas
    14       16       13  
Average cost of fuel per net KWH generated (cents)
    2.77       2.32       2.11  
Average cost of purchased power per net KWH (cents)
    8.39       4.97       3.29  
 
     Purchased power expense in 2005 increased $32.5 million, or 49.3 percent, as compared to 2004, primarily due to an increase in volume and cost of energy purchased from affiliates to meet the Company’s higher territorial load. 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.
     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 increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an immediate market response; however, the long-term 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 by the Company’s fuel cost recovery provisions.
Other Operation and Maintenance
In 2005, other operation and maintenance expenses increased $20.1 million, or 8.7 percent, as compared to

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the prior year primarily due to the recovery of $20.4 million in Hurricane Ivan restoration costs as approved by the Florida PSC. Since these expenses are recognized as revenues are collected, there is no impact on net income. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. In 2004, other operation and maintenance expenses increased $19.0 million, or 9.0 percent, as compared to the prior year primarily due to increases of $7.9 million in the property damage reserve, $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. In 2003, other operation and maintenance expenses increased $10.6 million, or 5.3 percent, as compared to the prior year primarily due to an increase of $1.6 million of customer accounts expense and an increase of $7.1 million in the property damage reserve. See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively, for additional information on the property damage reserve.
Depreciation and Amortization
Depreciation and amortization expense increased $2.2 million, or 2.7 percent, in 2005 as compared to the prior year primarily due to the completion of environmental control projects at Plant Crist Unit 7. Depreciation and amortization expense remained relatively flat in 2004 as compared to the prior year due to no significant change in depreciable assets. Depreciation and amortization expense increased $5.3 million, or 6.9 percent, in 2003 as compared to the prior year primarily due to the commercial operation of Plant Smith Unit 3. The 2003 increase also reflects the amortization of a regulatory asset related to corporate facilities, in accordance with an order from the Florida PSC.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $6.5 million, or 9.3 percent, in 2005, $3.7 million, or 5.7 percent, in 2004, and $5.1 million, or 8.3 percent, in 2003 primarily due to increases in franchise and gross receipts taxes, which are directly related to the increase in retail revenues. Taxes other than income taxes for 2003 also increased as a result of higher property taxes.
Other Income and (Expense)
The equity portion of allowance for funds used during construction (AFUDC) decreased $0.7 million, or 37.1 percent, in 2005 and increased $1.1 million, or 160.7 percent, in 2004 as compared to the prior year primarily due to environmental control projects at Plant Crist Unit 7. AFUDC decreased $2.3 million, or 76.1 percent, in 2003 as compared to the prior year primarily due to the completion of Plant Smith Unit 3. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” herein and Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information.
     Interest income increased $2.6 million, or 210.9 percent, in 2005 as compared to the prior year primarily due to interest received from a tax refund resulting from Hurricane Ivan and interest received related to the recovery of financing costs associated with Hurricane Ivan. See FUTURE EARNINGS POTENTIAL – “Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. Interest income remained relatively flat in 2004 and 2003 as compared to the prior year.
     Interest expense, net of amounts capitalized increased $4.2 million, or 13.5 percent, in 2005 as compared to the prior year as the result of higher interest rates on variable-rate pollution control bonds and an increase in outstanding short-term debt as a result of hurricane related costs. Interest expense decreased $2.1 million, or 5.5 percent, in 2004 as compared to the prior year and $1.8 million, or 4.6 percent, in 2003 as compared to the prior year primarily as the result of refinancing higher cost securities.
     Other deductions decreased $1.4 million, or 32.2 percent, in 2005 and $1.5 million, or 25.7 percent, in 2004 and increased $1.4 million, or 33.9 percent, in 2003 as compared to the prior years as a result of changes in charitable contributions.
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

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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 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 under “FERC Matters” and “Retail Regulatory Matters” 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 ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, 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.
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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, 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 EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant 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 allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled.
     On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters – New Source Review Actions” for additional information.

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     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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The Florida Department of Environmental Protection (FDEP) formally adopted the 2002 NSR rules in January 2006, but did not adopt the provisions vacated by the court. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Florida’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
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. Applicable statutes 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 these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $171.5 million in capital projects to comply with these requirements, with annual totals of $45.3 million, $67.2 million, and $37.7 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $761 million, including $48 million, $131 million, and $141 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost,

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availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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 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 “Retail Regulatory Matters – Environmental Cost Recovery.” Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the environmental cost recovery clause.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $52.4 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO2 and NOx emissions, to maintain compliance with existing regulations, and to meet new requirements.
     In 2005, the Company substantially completed the terms of a 2002 agreement with the State of Florida calling for NOx emission reductions at Plant Crist to help ensure attainment of the new standards in the Pensacola, Florida area. The conditions of the agreement, which required installing additional controls on Plant Crist units and retiring Plant Crist Units 1, 2, and 3, will be fully implemented by the end of 2006 at a cost of approximately $134.4 million, of which $4.3 million remains to be spent.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. With the exception of Macon, Georgia, where Plant Scherer is located, no area within the Company’s service area has been designated as nonattainment under the eight-hour ozone standard. State implementation plans, including new emission control regulations necessary to bring nonattainment areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NOx emissions from power plants.
     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for areas within Georgia, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO2 and NOx emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including Florida and Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power

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plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2, NOx, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.
Environmental Remediation
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 the 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 clean up costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Remediation” for additional information.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 – 2012. The Company is continuing to evaluate future energy and emissions profiles relative to the Climate VISION

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program and is analyzing voluntary programs to support the industry initiative.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, the Company, Mississippi Power, Savannah Electric, Southern Power, and Southern Company Services, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an

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adverse ruling in this proceeding, 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 three previously executed interconnection agreements with subsidiaries of Southern Company, including the 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. These proceedings are still pending at the FERC. The Company has received similar requests from other entities totaling approximately $6.7 million. The Company has opposed all such requests. 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.
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 “Market-Based Rate Authority” and “Generation Interconnection Agreements” above 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.
PSC Matters
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Florida PSC. Over the past year, the Company has continued to experience higher than expected fuel costs for coal and natural gas. At December 31, 2005 and 2004, the under recovered balance was $31.6 million and $7.9 million, respectively, primarily due to increased costs for coal and natural gas. The Company continuously monitors the under recovered fuel cost balance in light of these higher fuel costs. If the projected fuel revenue over or under recovery exceeds 10 percent of the projected fuel costs for the period, the Company is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary.
     In December 2005, the Florida PSC approved an increase of approximately 9 percent in the fuel factor for retail customers, effective with billings beginning January 2006. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on the Company’s revenues or net income, but would change annual cash flow.
Storm Damage Cost Recovery
Under authority granted by the Florida PSC, the Company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property. See Note 1 to the financial statements under “Property Damage Reserve” for additional information.
     In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama causing substantial damage to the Company’s service territory. The related costs charged to the Company’s property damage reserve as of December 31, 2004 were $93.5 million. In February 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 (Stipulation) with the Florida PSC, which the Florida PSC subsequently approved in March 2005, allowing the Company to 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

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retail customer bills for a 24-month period that began in April 2005. As of December 31, 2005, the Company had recovered $21.2 million of these costs. Under the Stipulation, the Company also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.
     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused additional damage in the Company’s service area. Hurricanes Dennis and Katrina restoration costs were approximately $64 million, of which approximately $56 million relates to operation and maintenance expenses. Approximately $1 million of these costs is expected to be covered through insurance.
     Prior to Hurricane Ivan, the Company’s reserve balance was approximately $27.8 million. The Company made discretionary accruals to the reserve of $6 million and $15 million in 2005 and 2004, respectively. As of December 31, 2005, the deficit balance in the Company’s property damage reserve accounts totaled approximately $43.6 million, of which approximately $3.5 million and $40.1 million, respectively, is included in the balance sheets herein under Current Assets and Deferred Charges and Other Assets. The established policy of the Florida PSC, as recently reaffirmed by its decision following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge.
     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, the Company filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over eight years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve the Company’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish the Company’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since the Company will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on the Company’s net income, but would increase cash flow.
     See Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information.
Other Matters
On September 15, 2005, the Company’s Board of Directors, and on October 27, 2005, the sole shareholder of the Company at that time, approved a Plan of Domestication pursuant to Maine law in order to domesticate the Company as a Florida corporation. By domesticating the Company in the same state where it operates as an electric utility subject to state regulation, the Company simplified certain state and federal regulatory compliance requirements. The Company was formed in 1925 as a Maine corporation and was qualified to do business in Florida as a foreign corporation the following year when it began operations as an electric utility. The Company was also admitted to do business in Mississippi in 1976 and in Georgia in 1984. The Company has maintained its principal place of business in Florida continuously since 1926. The domestication was effective as of November 2, 2005. The Company is now a Florida corporation. Under the applicable provisions of Florida law, the Company’s legal existence was uninterrupted, with only its state of incorporation changed.
     In 2004, Georgia Power and the Company entered into PPAs with FP&L and Progress Energy Florida. Under the agreements, Georgia Power and the Company will provide FP&L and Progress Energy Florida with 165 megawatts and 74 megawatts, respectively, 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 contracts in 2005.
     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

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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 pre-tax pension income of approximately $0.8 million, $2.5 million, and $4.9 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $4.8 million, $5.1 million, and $4.9 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension 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. Management has reviewed and discussed critical accounting policies and estimates 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 (Statement No. 71), 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 and accounting principles generally accepted in the United States. 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

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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 (IRS) 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, the EPA, or the FDEP.
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
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on the Company’s financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $9.1 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”
Stock Options
On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition continued to be stable at December 31, 2005. Net cash flow from operating activities totaled $152.7 million, $143.2 million, and $191.2 million for 2005, 2004, and 2003, respectively. The increase from 2004 to 2005 is due primarily to the recovery of Hurricane Ivan restoration costs. The majority

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of the decrease from 2003 to 2004 is due to payments related to storm damage from Hurricane Ivan. See “Financing Activities” herein for additional information. Property additions were $142.6 million in 2005. 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.
     The Company’s ratio of common equity to total capitalization, including short-term debt, was 43.0 percent in 2005, 43.2 percent in 2004, and 45.3 percent in 2003. 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 from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.
     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 or preference 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 is subject to regulatory approval by the Florida PSC pursuant to its rules and regulations. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida 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. 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 the Company are not commingled with funds of any other company.
     The Company’s current liabilities exceed current assets due to the scheduled maturity of $37.1 million of long-term debt in 2006. 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 2006, the Company had approximately $3.8 million of cash and cash equivalents, along with $120.5 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire during 2006. The Company plans to renew these lines of credit during 2006. 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 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. There is no cross affiliate credit support. At December 31, 2005, the Company had $15 million in commercial paper notes and $75 million in bank notes outstanding.
Financing Activities
During 2005, the Company issued $60 million of senior notes. A portion of the proceeds of this issuance was used for the legal defeasance of $30 million of principal of first mortgage bonds. The remainder of the funds from the sale of senior notes was used for general corporate purposes. In October 2005, the Company entered into a $60 million revolving credit agreement and a $75 million 364-day bank loan. A portion of these facilities was used to fund or refinance costs related to Hurricanes Ivan, Dennis, and Katrina with the remainder used to support the Company’s

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increased obligations with respect to its commercial paper program, which will also be used to fund storm-related costs. In addition, in October 2005, the Company redeemed all outstanding shares of its three preferred stock issues, totaling $4.2 million, in conjunction with the domestication of the Company as a Florida corporation. In November 2005, the Company issued $55 million of preference stock. The funds resulting from this issuance were used for general corporate purposes. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” and “– Other Matters” herein 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 for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005, 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 management activities. At December 31, 2005, the Company had no material exposure related to these agreements.
Market Price Risk
The 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.
     Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for natural gas purchases. The Company has implemented a fuel-hedging program with the approval of the Florida PSC.
     The weighted average interest rate on $144.6 million variable long-term debt that has not been hedged at January 1, 2006 was 3.3 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 at January 1, 2006. 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  
    2005     2004  
    (in thousands)  
Contracts beginning of year
  $ 317     $ 2,503  
Contracts realized or settled
    (15,023 )     (8,409 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    26,232       6,223  
 
Contracts end of year
  $ 11,526     $ 317  
 
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2005 Year-End
    Valuation Prices
    Total   Maturity
    Fair Value   2006   2007-2008
    (in thousands)
 
Actively quoted
  $ 11,568     $ 7,770     $ 3,798  
External sources
    (42 )     (42 )      
Models and other methods
                 
 
Contracts end of Year
  $ 11,526     $ 7,728     $ 3,798  
 

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2005 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 statements of income as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 11,540  
Other comprehensive income
     
Net income
    (14 )
 
Total fair value
  $ 11,526  
 
     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 $163 million in 2006, $221 million in 2007, and $221 million in 2008. The construction program also includes $48 million in 2006, $131 million in 2007, and $141 million in 2008 for environmental expenditures. Actual construction costs may vary from these estimates 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 under construction. 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, is 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 FERC and the Florida PSC.
     Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, derivative obligations, preference 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)
Gulf Power Company 2005 Annual Report
                                         
            2007-   2009-   After    
Contractual Obligations   2006   2008   2010   2010   Total
                    (in thousands)                
Long-term debt(a)
                                       
Principal
  $ 37,075     $     $     $ 624,721     $ 661,796  
Interest
    33,055       61,592       61,592       625,399       781,638  
Commodity derivative obligations(b)
    2,444       8                   2,452  
Preference stock dividends(c)
    3,300       6,600       6,600             16,500  
Operating leases
    4,875       7,363       4,169       4,170       20,577  
Purchase commitments(d)
                                       
Capital(e)
    162,711       441,554                   604,265  
Coal
    240,647       92,694                   333,341  
Natural gas(f)
    123,447       116,683       37,772       204,030       481,932  
Long-term service agreements
    5,711       13,077       16,203       43,064       78,055  
Postretirement benefit trusts(g)
    70       140                   210  
 
Total
  $ 613,335     $ 739,711     $ 126,336     $ 1,501,384     $ 2,980,766  
 
 
(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, 2006, as reflected in the statements of capitalization.
 
(b)   For additional information, see Notes 1 and 6 to the financial statements herein.
 
(c)   Preference stock does not mature; therefore, amounts are provided for the next five years only.
 
(d)   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 $250 million, $230 million, and $211 million, respectively.
 
(e)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
 
(f)   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, 2005.
 
(g)   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)
Gulf Power Company 2005 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2005 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, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, 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, implementation of the Energy Policy Act of 2005, 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 actions against the Company, FERC matters, and IRS audits;
  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, including rate cases relating to fuel cost recovery;
  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 Securities and Exchange Commission.
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, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report
                         
    2005   2004   2003
            (in thousands)        
Operating Revenues:
                       
Retail sales
  $ 864,859     $ 736,870     $ 699,174  
Sales for resale —
                       
Non-affiliates
    84,346       73,537       76,767  
Affiliates
    91,352       110,264       63,268  
Other revenues
    43,065       39,460       38,488  
 
Total operating revenues
    1,083,622       960,131       877,697  
 
Operating Expenses:
                       
Fuel
    415,789       367,155       316,503  
Purchased power —
                       
Non-affiliates
    29,995       30,720       17,137  
Affiliates
    68,402       35,177       33,020  
Other operations
    176,620       160,635       140,166  
Maintenance
    73,150       69,077       70,534  
Depreciation and amortization
    85,002       82,799       82,322  
Taxes other than income taxes
    76,387       69,856       66,115  
 
Total operating expenses
    925,345       815,419       725,797  
 
Operating Income
    158,277       144,712       151,900  
Other Income and (Expense):
                       
Interest income
    3,804       1,224       888  
Interest expense, net of amounts capitalized
    (35,727 )     (31,482 )     (31,069 )
Interest expense to affiliate trusts
    (4,590 )     (3,443 )      
Distributions on mandatorily redeemable preferred securities
          (1,113 )     (7,085 )
Other income (expense), net
    (813 )     (1,763 )     (4,530 )
 
Total other income and (expense)
    (37,326 )     (36,577 )     (41,796 )
 
Earnings Before Income Taxes
    120,951       108,135       110,104  
Income taxes
    44,981       39,695       40,877  
 
Net Income
    75,970       68,440       69,227  
Dividends on Preferred and Preference Stock
    761       217       217  
 
Net Income After Dividends on Preferred and Preference Stock
  $ 75,209     $ 68,223     $ 69,010  
 
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, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report
                         
    2005   2004   2003
            (in thousands)        
Operating Activities:
                       
Net income
  $ 75,970     $ 68,440     $ 69,227  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    90,890       88,772       87,949  
Deferred income taxes
    33,161       46,255       2,303  
Pension, postretirement, and other employee benefits
    375       (895 )     (717 )
Tax benefit of stock options
    3,502       3,063       1,768  
Hedge settlements
                (3,266 )
Other, net
    3,958       11,402       6,795  
Changes in certain current assets and liabilities —
                       
Receivables
    (46,248 )     543       8,165  
Fossil fuel stock
    (11,740 )     2,355       1,837  
Materials and supplies
    3,785       (831 )     (1,091 )
Prepaid income taxes
    31,898       (32,343 )     12,701  
Property damage cost recovery
    20,045              
Other current assets
    3,453       2,721       (704 )
Accounts payable
    (72,532 )     (51,876 )     (1,512 )
Accrued taxes
    6,847       629       (549 )
Accrued compensation
    311       1,946       104  
Other current liabilities
    9,011       4,325       8,300  
 
Net cash provided from operating activities
    152,686       144,506       191,310  
 
Investing Activities:
                       
Property additions
    (143,171 )     (148,765 )     (98,572 )
Cost of removal net of salvage
    (8,504 )     (10,259 )     (7,881 )
Construction payables
    (8,806 )     13,682       (2,726 )
Other
    (440 )     8,952       (2,545 )
 
Net cash used for investing activities
    (160,921 )     (136,390 )     (111,724 )
 
Financing Activities:
                       
Increase in notes payable, net
    39,465       12,334       9,187  
Proceeds —
                       
Pollution control bonds
                61,625  
Senior notes
    60,000       110,000       225,000  
Other long-term debt
          100,000        
Preferred and preference stock
    55,000              
Capital contributions from parent company
    (94 )     29,481       13,315  
Redemptions —
                       
Pollution control bonds
                (61,625 )
First mortgage bonds
    (30,000 )            
Senior notes
          (125,000 )     (151,757 )
Other long-term debt
    (100,000 )           (20,000 )
Preferred and preference stock
    (4,236 )            
Mandatorily redeemable preferred securities
                (85,000 )
Payment of preferred and preference stock dividends
    (761 )     (217 )     (217 )
Payment of common stock dividends
    (68,400 )     (70,000 )     (70,200 )
Other
    (3,721 )     (2,433 )     (10,644 )
 
Net cash provided from (used for) financing activities
    (52,747 )     54,165       (90,316 )
 
Net Change in Cash and Cash Equivalents
    (60,982 )     62,281       (10,730 )
Cash and Cash Equivalents at Beginning of Year
    64,829       2,548       13,278  
 
Cash and Cash Equivalents at End of Year
  $ 3,847     $ 64,829     $ 2,548  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $515, $819, and $314 capitalized, respectively)
  $ 35,786     $ 28,796     $ 37,468  
Income taxes (net of refunds)
    (27,912 )     24,130       23,777  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Gulf Power Company 2005 Annual Report
                 
Assets
    2005   2004  
 
    (in thousands)
Current Assets:
               
Cash and cash equivalents
  $ 3,847     $ 64,829  
Receivables —
               
Customer accounts receivable
    51,567       44,255  
Unbilled revenues
    39,951       35,889  
Under recovered regulatory clause revenues
    33,205       9,283  
Other accounts and notes receivable
    10,533       7,177  
Affiliated companies
    24,001       16,218  
Accumulated provision for uncollectible accounts
    (1,134 )     (2,144 )
Fossil fuel stock, at average cost
    44,740       32,999  
Materials and supplies, at average cost
    32,976       36,761  
Prepaid income taxes
    295       34,812  
Property damage cost recovery
    28,744       3,500  
Other regulatory assets
    9,895       9,043  
Other
    19,341       5,198  
 
Total current assets
    297,961       297,820  
 
Property, Plant, and Equipment:
               
In service
    2,502,057       2,367,189  
Less accumulated provision for depreciation
    865,989       844,617  
 
 
    1,636,068       1,522,572  
Construction work in progress
    28,177       75,218  
 
Total property, plant, and equipment
    1,664,245       1,597,790  
 
Other Property and Investments
    6,736       6,425  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    17,379       17,566  
Prepaid pension costs
    46,374       45,384  
Other regulatory assets
    123,258       127,190  
Other
    19,844       19,702  
 
Total deferred charges and other assets
    206,855       209,842  
 
Total Assets
  $ 2,175,797     $ 2,111,877  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Gulf Power Company 2005 Annual Report
                 
           
Liabilities and Stockholder’s Equity   2005     2004  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 37,075     $ 100,000  
Notes payable
    89,465       50,000  
Accounts payable —
               
Affiliated
    36,717       35,359  
Other
    44,139       77,452  
Customer deposits
    18,834       18,470  
Accrued taxes —
               
Income taxes
    12,823       1,927  
Other
    11,689       9,250  
Accrued interest
    7,713       7,665  
Accrued compensation
    20,336       16,989  
Other regulatory liabilities
    15,671       6,469  
Other
    21,844       13,179  
 
Total current liabilities
    316,306       336,760  
 
Long-term Debt (See accompanying statements)
    544,388       550,989  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    72,166       72,166  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    256,490       229,909  
Accumulated deferred investment tax credits
    16,569       18,489  
Employee benefit obligations
    56,235       54,869  
Other cost of removal obligations
    153,665       155,831  
Other regulatory liabilities
    26,795       25,402  
Other
    76,948       71,192  
 
Total deferred credits and other liabilities
    586,702       555,692  
 
Total Liabilities
    1,519,562       1,515,607  
 
Preferred and Preference Stock (See accompanying statements)
    53,891       4,098  
 
Common Stockholder’s Equity (See accompanying statements)
    602,344       592,172  
 
Total Liabilities and Stockholder’s Equity
  $ 2,175,797     $ 2,111,877  
 
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, 2005 and 2004
Gulf Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
    (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                  
 
Total first mortgage bonds
    25,000       55,000                  
 
Long-term notes payable —
                               
Variable rate (2.36% at 1/1/05) due October 28, 2005
          100,000                  
4.35% to 5.88% due 2013-2044
    395,000       335,000                  
 
Total long-term notes payable
    395,000       435,000                  
 
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 (3.10% to 3.80% at 1/1/06) due 2022-2037
    144,555       144,555                  
 
Total other long-term debt
    169,630       169,630                  
 
Unamortized debt premium (discount), net
    (8,167 )     (8,641 )                
 
Total long-term debt (annual interest requirement — $28.5 million)
    581,463       650,989                  
Less amount due within one year
    37,075       100,000                  
 
Long-term debt excluding amount due within one year
    544,388       550,989       42.8 %     45.2 %
 
Long-term Debt Payable to Affiliated Trusts:
                               
5.6% to 7.38% due 2041 through 2042 (annual interest requirement — $4.6 million)
    72,166       72,166       5.7       5.9  
 
Preferred and Preference Stock:
                               
Cumulative preferred stock
                               
$100 par value
                               
Authorized — 10,000,000 shares
                               
Outstanding — No shares in 2005, 42,361 shares in 2004 4.64% to 5.44%
          4,098                  
Non-cumulative preference stock
                               
$100 par or stated value — 6.00%
                               
Authorized — 10,000,000 shares
                               
Outstanding — 550,000 shares
    53,891                        
 
Total preferred and preference stock (annual dividend requirement — $3.3 million)
    53,891       4,098       4.2       0.3  
 
Common Stockholder’s Equity:
                               
Common stock, without par value —
                               
Authorized — 10,000,000 shares
                               
Outstanding — 992,717 shares
    38,060       38,060                  
Paid-in capital
    400,815       397,396                  
Retained earnings
    166,279       159,581                  
Accumulated other comprehensive income (loss)
    (2,810 )     (2,865 )                
 
Total common stockholder’s equity
    602,344       592,172       47.3       48.6  
 
Total Capitalization
  $ 1,272,789     $ 1,219,425       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, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report
                                         
                            Other    
    Common   Paid-In   Retained   Comprehensive    
    Stock   Capital   Earnings   Income (loss)   Total
 
    (in thousands)
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  
Net income after dividends on preferred and preference stock
                75,209             75,209  
Capital contributions from parent company
          3,408                   3,408  
Other comprehensive income (loss)
                      55       55  
Cash dividends on common stock
                (68,400 )           (68,400 )
Other
          11       (111 )           (100 )
 
Balance at December 31, 2005
  $ 38,060     $ 400,815     $ 166,279     $ (2,810 )   $ 602,344  
 
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report
                         
    2005     2004     2003  
 
        (in thousands)
Net income after dividends on preferred and preference stock
  $ 75,209     $ 68,223     $ 69,010  
 
Other comprehensive income (loss):
                       
Changes in additional minimum pension liability, net of tax of $(91), $(184) and $(84), respectively
    (146 )     (292 )     (134 )
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 $126, $91 and $63
    201       145       100  
 
Total other comprehensive income (loss)
    55       (91 )     (2,040 )
 
Comprehensive Income
  $ 75,264     $ 68,132     $ 66,970  
 
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2005 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), 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). 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 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. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
     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 was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were 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.
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 $54 million, $56 million, and $55 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, 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 $4.3 million, $6.8 million, and $4.9 million and Mississippi Power $18.4 million, $17.8 million, and $17.7 million in 2005, 2004, and 2003, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information.
     The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in the last two years, assistance provided to aid in storm restoration, including Company labor, contract labor, and materials, has caused an increase in

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NOTES (continued)
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these activities. The total amount of storm restoration provided to Mississippi Power in 2005 was $11.1 million. These activities were billed at cost. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $5.8 million and $12.7 million in 2005 and 2004, respectively.
     The retail operating companies, including the Company, and Southern Power 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.
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:
                         
    2005   2004   Note
    (in thousands)        
Environmental remediation
  $ 58,235     $ 59,364       (a )
Loss on reacquired debt
    19,433       19,197       (b )
Vacation pay
    5,662       5,446       (c )
Deferred income tax charges
    17,379       17,566       (d )
Fuel-hedging assets
    2,411       1,685       (e )
Other assets
    3,374       5,656       (f )
Under recovered regulatory clause revenues
    31,634       7,931       (f )
Property damage recovery
    30,778             (g )
Property damage reserve
    43,574       48,284       (f )
Asset retirement obligations
    (640 )     1,453       (d )
Other cost of removal obligations
    (153,665 )     (155,831 )     (d )
Deferred income tax credits
    (20,627 )     (23,354 )     (d )
Fuel-hedging liabilities
    (13,950 )     (1,994 )     (e )
Over recovered regulatory clause revenues
    (5,333 )     (4,554 )     (f )
Other liabilities
    (1,916 )     (1,967 )     (f )
 
Total
  $ 16,349     $ (21,118 )        
 
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)   Recovered through the environmental cost recovery clause when the expense is incurred.
 
(b)   Recovered over the remaining life of the original issue, which may range up to 40 years.
 
(c)   Recorded as earned by employees and recovered as paid, generally within one year.
 
(d)   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.
 
(e)   Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
 
(f)   Recorded and recovered or amortized as approved by the Florida PSC.
 
(g)   Recorded and recovered over 24 months ending March 2007 as approved by the Florida PSC.
     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.
Revenues
Energy and other revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Capacity revenues are generally recognized on a levelized basis over the appropriate contract period. 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. If the projected fuel revenue over or under recovery exceeds 10 percent of the projected fuel costs for the period, the Company is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary. 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 these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of

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projected costs including any true-up amount from prior periods, and approved rates are implemented each January.
     The Company has a diversified base of customers and no single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged significantly less than 1 percent of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is 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 life of the related property.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits, and the interest capitalized and/or estimated cost of funds used during construction. The Company’s property, plant, and equipment consisted of the following at December 31:
                 
    2005     2004  
    (in thousands)  
Generation
  $ 1,326,766     $ 1,237,184  
Transmission
    262,168       254,506  
Distribution
    788,711       754,667  
General
    120,339       116,503  
Plant acquisition adjustment
    4,073       4,329  
 
Total plant in service
  $ 2,502,057     $ 2,367,189  
 
     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.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.8 percent in each of 2005, 2004, and 2003. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida 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 the accumulated provision for 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.
Asset Retirement Obligations and Other Costs of Removal
Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which 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 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. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in 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 or Interpretation No. 47.
     The liability recognized to retire long-lived assets primarily relates to the Company’s combustion turbines at its Pea Ridge facility, various landfill sites, and a barge unloading dock. In connection with the adoption of Interpretation of No. 47, the Company has also recorded additional asset retirement obligations (and

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Gulf Power Company 2005 Annual Report
assets) of $9.1 million, primarily related to asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company has also identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. 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 Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets.
     Details of the asset retirement obligations included in the balance sheets are as follows:
                 
    2005   2004
    (in thousands)
Balance beginning of year
  $ 5,789     $ 4,271  
Liabilities incurred
    9,122        
Liabilities settled
           
Accretion
    387       316  
Cash flow revisions
          1,202  
 
Balance end of year
  $ 15,298     $ 5,789  
 
     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $14.3 million.
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 2005, 2004, and 2003, the average annual AFUDC rate was 7.48 percent. AFUDC, net of taxes, as a percentage of net income after dividends on preferred and preference stock was 1.97 percent, 3.46 percent, and 1.31 percent, respectively, for 2005, 2004, and 2003.
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.
Property Damage Reserve
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The cost of such damages is charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve 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 $9.5 million in 2005, $18.5 million in 2004, and $10.6 million in 2003. At December 31, 2005, the deficit balance in the property damage reserve was $43.6 million, of which approximately $3.5 million and $40.1 million is included in Current Assets and Deferred Charges and Other Assets, respectively, in the balance sheets. See Note 3 under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information regarding the depletion of these reserves following Hurricanes Ivan, Dennis, and Katrina, and the deferral of additional costs, as well as additional surcharges or other cost recovery mechanisms approved by the Florida PSC to replenish these reserves.
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

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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 environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually each January. In September 2004, the Company increased its liability for the estimated costs of environmental remediation projects by approximately $47 million. This increase related 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 company 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 the Company’s environmental cost recovery clause; therefore, there was no impact on the Company’s net income as a result of these revised estimates. The liability balances as of December 31, 2005 and 2004 were $58.2 million and $59.4 million, respectively. See Note 3 under “Retail Regulatory Matters – Environmental Remediation” for additional information.
Injuries and Damages Reserve
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 reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. At both December 31, 2005 and 2004, the injuries and damages reserve was $1.7 million and is included in Current Liabilities in the balance sheets. Liabilities in excess of the reserve balance of $3.0 million and $4.8 million at December 31, 2005 and 2004, respectively, are included in Deferred Credits and Other Liabilities in the balance sheets. Corresponding regulatory assets of $1.6 million at both December 31, 2005 and 2004 are included in Current Assets in the balance sheets. At December 31, 2005 and 2004, respectively, $1.4 million and $3.2 million are included in Deferred Charges and Other Assets in the balance sheets.
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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used.
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.
     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on net income is as follows:
                         
    As     Options     Pro  
    Reported     Impact     Forma  
    (in thousands)  
2005
  $ 75,209     $ (586 )   $ 74,623  
2004
    68,223       (522 )     67,701  
2003
    69,010       (593 )     68,417  
 

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     The estimated fair values of stock options granted in 2005, 2004, and 2003 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:
                         
    2005   2004   2003
 
Interest rate
    3.9 %     3.1 %     2.7 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.9 %     19.6 %     23.6 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
 
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 or are recoverable through the Florida PSC approved hedging program. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from the cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
     The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
     Other financial instruments for which the carrying amount does not equal fair value at December 31 were as follows:
                 
    Carrying     Fair  
    Amount     Value  
    (in thousands)  
Long-term debt:
               
2005
  $ 653,629     $ 644,677  
2004
    723,155       729,821  
 
     The fair values were based on either closing market price or closing price of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, 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
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments for the Company, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees.

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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, 2006, postretirement trust contributions are expected to total approximately $70,000.
     The measurement date for plan assets and obligations is September 30 of each year presented.
Pension Plans
The total accumulated benefit obligation for the pension plans was $226 million in 2005 and $204 million in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
                 
    Projected  
    Benefit Obligations  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 228,414     $ 206,486  
Service cost
    6,318       5,915  
Interest cost
    12,866       12,136  
Benefits paid
    (10,081 )     (9,499 )
Actuarial (gain)/loss and employee transfers, net
    10,509       13,376  
 
Balance at end of year
  $ 248,026     $ 228,414  
 
                 
    Plan Assets  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 250,238     $ 236,345  
Actual return on plan assets
    38,478       23,152  
Employer contributions
    732       550  
Benefits paid
    (10,081 )     (9,499 )
Employee transfers
    999       (310 )
 
Balance at end of year
  $ 280,366     $ 250,238  
 
     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $236 million and $12 million, respectively. All plan assets are related to the qualified plan.
     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     2005     2004  
 
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
                 
    Accrued Pension Costs  
    2005     2004  
    (in thousands)  
Funded status
  $ 32,340     $ 21,824  
Unrecognized transition amount
          (721 )
Unrecognized prior service cost
    12,780       12,434  
Unrecognized net (gain)/loss
    (3,645 )     7,511  
 
Prepaid pension asset, net
  $ 41,475     $ 41,048  
 
     The prepaid pension asset, net is reflected in the balance sheets in the following line items:
                 
    2005     2004  
    (in thousands)  
Prepaid pension asset
  $ 46,374     $ 45,384  
Employee benefit obligations
    (7,893 )     (7,316 )
Other property and investments — other
    868       1,091  
Accumulated other comprehensive income
    2,126       1,889  
         
Prepaid pension asset, net
  $ 41,475     $ 41,048  
         

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     Components of the pension plans’ net periodic cost were as follows:
                         
    2005     2004     2003  
    (in thousands)  
Service cost
  $ 6,317     $ 5,915     $ 5,225  
Interest cost
    12,866       12,136       11,733  
Expected return on plan assets
    (20,816 )     (20,689 )     (20,564 )
Recognized net (gain)/loss
    350       (317 )     (1,819 )
Net amortization
    502       486       486  
 
Net pension income
  $ (781 )   $ (2,469 )   $ (4,939 )
 
     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, 2005, estimated benefit payments were as follows:
         
    Benefit
    Payments
    (in thousands)
2006
  $ 10,459  
2007
    10,756  
2008
    11,053  
2009
    11,403  
2010
    11,895  
2011 to 2015
  $ 69,865  
 
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  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 69,186     $ 72,903  
Service cost
    1,357       1,275  
Interest cost
    3,892       4,080  
Benefits paid
    (3,124 )     (2,447 )
Actuarial (gain)/loss
    1,969       (6,625 )
 
Balance at end of year
  $ 73,280     $ 69,186  
 
                 
    Plan Assets  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 14,296     $ 12,642  
Actual return on plan assets
    2,114       1,594  
Employer contributions
    3,148       2,507  
Benefits paid
    (3,124 )     (2,447 )
 
Balance at end of year
  $ 16,434     $ 14,296  
 
     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     2005     2004  
 
Domestic equity
    34 %     38 %     34 %
International equity
    23       23       19  
Fixed income
    19       21       30  
Real estate
    14       12       10  
Private equity
    10       6       7  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
                 
    2005     2004  
    (in thousands)  
Funded status
  $ (56,846 )   $ (54,891 )
Unrecognized transition obligation
    2,589       2,944  
Unrecognized prior service cost
    4,311       4,657  
Unrecognized net (gain)/loss
    9,026       8,074  
Fourth quarter contributions
    973       829  
 
Accrued liability recognized in the balance sheets
  $ (39,947 )   $ (38,387 )
 
     Components of the postretirement plans’ net periodic cost were as follows:
                         
    2005     2004     2003  
    (in thousands)  
Service cost
  $ 1,357     $ 1,275     $ 1,128  
Interest cost
    3,892       4,081       4,058  
Expected return on plan assets
    (1,202 )     (1,220 )     (1,139 )
Transition obligation
    356       355       356  
Prior service cost
    346       346       346  
Recognized net (gain)/loss
    33       241       113  
 
Net postretirement cost
  $ 4,782     $ 5,078     $ 4,862  
 
     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to

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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 and for the year ended December 31, 2005 by approximately $0.5 million and $1.1 million, respectively, and is expected to have a similar impact on future years.
     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)        
2006
  $ 3,628     $ (315 )   $ 3,313  
2007
    3,803       (399 )     3,404  
2008
    4,146       (456 )     3,690  
2009
    4,518       (508 )     4,010  
2010
    4,881       (558 )     4,323  
2011 to 2015
  $ 27,109     $ (3,936 )   $ 23,173  
 
Actuarial Assumptions
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:
                         
    2005     2004     2003  
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00 %     3.50 %     3.75 %
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, 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, 2005 as follows:
                 
    1 Percent
    Increase   Decrease
    (in thousands)
Benefit obligation
  $ 4,745     $ 4,254  
Service and interest costs
  $ 310     $ 276  
 
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 2005, 2004, and 2003, were $2.9 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 such as opacity and other air quality standards, 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 pending or potential 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.

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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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, 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 EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant Scherer. See Note 4 herein 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 allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled.
     On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
     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.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a

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result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, the Company, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 three previously executed interconnection agreements with subsidiaries of Southern Company, including the 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. These proceedings are still pending at the FERC. The Company has received similar requests from other entities totaling $6.7 million. The Company has opposed all such requests. 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.
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. The Company’s management believe that it has complied with applicable laws and that the plaintiffs’ claims are without merit.
     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

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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. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against the Company on their respective motions for partial summary judgment. In that same order, the trial court also denied the Company’s motion to dismiss certain claims. The court’s ruling allowed for an immediate appeal to the Florida First District Court of Appeal, which the Company filed on December 20, 2005. If the appeal is not successful, damages will be decided at a future trial.
     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 landowner litigation discussed above. In January 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.
Property Tax Dispute
Georgia Power and the Company are involved in a significant property tax dispute with Monroe County, Georgia (Monroe County). The Monroe County Board of Tax Assessors (Monroe Board) has issued assessments reflecting substantial increases in the ad valorem tax valuation of Plant Scherer, of which Georgia Power and the Company own 22.95 percent and 6.25 percent, respectively, for tax years 2003, 2004, and 2005. Georgia Power and the Company are aggressively pursuing administrative appeals in Monroe County and have filed or will file Notices of Arbitration for all three years. The appeals are currently stayed, pending the outcome of the litigation discussed below.
     In addition, in November 2004, Georgia Power filed suit, on its own behalf, against the Monroe Board in the Superior Court of Monroe County. The suit could impact all co-owners. Georgia Power contends that Monroe County acted without statutory authority in changing the valuation of a centrally assessed utility as established by the Revenue Commissioner of the State of Georgia and requests injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from Georgia Power. On December 22, 2005, the Court granted Monroe County’s motion for summary judgment. Georgia Power has filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.
     If Georgia Power is not successful in its administrative appeals and if Monroe County is successful in defending the litigation, the Company could be subject to total additional taxes through December 31, 2005 of up to $3 million, plus penalties and interest. In accordance with the Company’s unit power sales contract for Plant Scherer, such property taxes would be recoverable from the customer. The final outcome of this matter cannot now be determined.
Retail Regulatory Matters
Environmental Cost Recovery
The Florida Legislature adopted legislation for an environmental cost recovery clause, 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 FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. During 2005, 2004, and 2003, the Company recorded environmental cost recovery clause revenues of $26.3 million, $14.7 million, and $10.9 million, respectively. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At

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December 31, 2005, the over recovered balance was $3.0 million primarily due to a delay in environmental projects.
Environmental Remediation
At December 31, 2005, the Company’s liability for the estimated costs of environmental remediation projects for known sites was $58.2 million. The schedule for completion of the remediation projects will be subject to FDEP approval. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause. Therefore, the Company has recorded $1.6 million in Current Assets and Current Liabilities and $56.6 million in Deferred Charges and Other Assets and Deferred Credits and Other Liabilities representing the future recoverability of these costs.
     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.
Storm Damage Cost Recovery
The Company maintains a reserve to recover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property.
     Hurricane Ivan hit the Gulf Coast of Florida and Alabama in September 2004, causing significant damage to the Company’s service territory. In March 2005, the Florida PSC approved a Stipulation and Settlement (Stipulation) among the Company, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group. The agreement allows the Company to recover the retail portion of $51.7 million in storm damage costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. As of December 31, 2005, the Company had recovered $21.2 million of these costs. Under the Stipulation, the Company also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.
     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused additional damage in the Company’s service area. Hurricanes Dennis and Katrina restoration costs were approximately $64 million, of which approximately $56 million relates to operation and maintenance expenses. Approximately $1 million of these costs is expected to be covered through insurance.
     As of December 31, 2005, the deficit balance in the Company’s property damage reserve accounts totaled approximately $43.6 million, of which approximately $3.5 million and $40.1 million, respectively, is included in the balance sheets under Current Assets and Deferred Charges and Other Assets. The established policy of the Florida PSC, as recently reaffirmed by its decision following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for the recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge.
     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, the Company filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over eight years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve the Company’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish the Company’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since the Company will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on the Company’s net income, but would increase cash flow.
     See Note 1 herein under “Property Damage Reserve” for additional information.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 megawatt (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.

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     The Company and Georgia Power jointly own the 818 MW capacity Plant Scherer Unit 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, 2005, the Company’s percentage ownership and its investment in these jointly owned facilities were as follows:
                 
    Plant     Plant  
    Scherer     Daniel  
    Unit 3     Units 1 & 2  
    (coal)     (coal)  
    (in thousands)  
Plant in service
  $ 190,534 (1)   $ 244,380  
Accumulated depreciation
    87,817       133,923  
Construction work in progress
    360       3,620  
Ownership
    25 %     50 %
 
(1)   Includes net plant acquisition adjustment of $4.1 million.
5. INCOME TAXES
Southern Company and its subsidiaries file a consolidated federal income tax return and combined State of Mississippi and State of Georgia income tax returns. Under a joint consolidated income tax allocation agreement, 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.
     At December 31, 2005, the tax-related regulatory assets to be recovered from customers were $17.4 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, 2005, the tax-related regulatory liabilities to be credited to customers were $20.6 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:
                         
    2005     2004     2003  
    (in thousands)  
Federal —
                       
Current
  $ 11,330     $ (4,255 )   $ 33,871  
Deferred
    26,693       39,373       1,702  
 
 
    38,023       35,118       35,573  
 
State —
                       
Current
    490       (2,305 )     4,703  
Deferred
    6,468       6,882       601  
 
 
    6,958       4,577       5,304  
 
Total
  $ 44,981     $ 39,695     $ 40,877  
 
     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:
                 
    2005     2004  
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 245,906     $ 218,137  
Fuel recovery clause
    12,812       3,212  
Pension benefits
    14,817       14,176  
Property reserve
    29,393       20,675  
Other
    6,352       15,029  
 
Total
    309,280       271,229  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    13,591       11,930  
Postretirement benefits
    13,430       12,588  
Pension benefits
    2,054       2,020  
Other comprehensive loss
    1,765       1,800  
Other
    13,082       11,055  
 
Total
    43,922       39,393  
 
Net deferred tax liabilities
    265,358       231,836  
Less current portion, net
    (8,868 )     (1,927 )
 
Accumulated deferred income taxes in the balance sheets
  $ 256,490     $ 229,909  
 
     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 $1.9 million in 2005, $2.0 million in 2004, and $1.8 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

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NOTES (continued)
Gulf Power Company 2005 Annual Report
     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
                         
    2005   2004   2003
Federal statutory rate
    35 %     35 %     35 %
State income tax, net of federal deduction
    4       3       3  
Non-deductible book depreciation
    1       1       1  
Difference in prior years’ deferred and current tax rate
    (1 )     (1 )     (1 )
Other, net
    (2 )     (1 )     (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 $72.2 million, which constitute substantially all of the assets of these 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 trusts’ payment obligations with respect to these securities. At December 31, 2005, $72.2 million of 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.
Securities Due Within One Year
At December 31, 2005, the Company had an improvement fund requirement of $250,000. 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 2004 and 2003. It is anticipated that the 2005 requirement will be satisfied by certifying property additions.
     The Company’s remaining first mortgage bonds mature in 2006; therefore, the only sinking fund requirements and/or maturities through 2010 are $37.1 million in 2006.
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 connection with the maturity of the Company’s remaining outstanding first mortgage bonds in November 2006, such lien will be removed. In addition, the Company has granted a second lien on its property at Plant Daniel in connection with the issuance of one 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 2006, the Company had $120.5 million of lines of credit with banks subject to renewal each year, all of which remained unused. Of the $120.5 million, $116.5 million provides liquidity support for the Company’s commercial paper program and $4.0 million of daily variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees.

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NOTES (continued)
Gulf Power Company 2005 Annual Report
     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, 2005, the Company was in compliance with these 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 primarily through a commercial paper program that has the liquidity support of committed bank credit arrangements. The Company may also borrow through various other arrangements with banks and through an extendible commercial note program. At December 31, 2005, the Company had $89.5 million in commercial paper and bank notes outstanding. At December 31, 2004, the Company had no commercial paper or extendible commercial notes outstanding. During 2005, the peak amount outstanding for commercial paper was $110 million and the average amount outstanding was $51.8 million. The average annual interest rate on commercial paper was 3.56 percent.
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 2005 and 2004.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 11,540  
Other comprehensive income
     
Net income
    (14 )
 
Total fair value
  $ 11,526  
 
     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 2008.
     The Company also may enter 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 and are generally structured to match the critical terms of the hedged debt instruments.
     The Company had no interest rate derivatives outstanding in 2005 or 2004. During 2003, the Company settled interest rate 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 approximately $0.3 million annually is reclassified to interest expense over the life of the related debt, which matures in 2013.
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $163 million in 2006, $221 million in 2007, and $221 million in 2008. 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, 2005, significant purchase commitments were outstanding in connection with the ongoing construction program.

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NOTES (continued)
Gulf Power Company 2005 Annual Report
     Included in the amounts above, are $48 million in 2006, $131 million in 2007, and $141 million in 2008 for environmental expenditures. The Company does not have any new generating capacity under construction. 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 Agreements
The Company has 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 provides 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 $78.1 million over the remaining life of the agreement. However, the LTSA contains various cancellation provisions at the option of the Company.
     Payments made to GE prior to the performance of any planned inspections are recorded as prepayments. These amounts are included in Current Assets and Deferred Charges and Other Assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Fuel Commitments
To supply a portion of the fuel requirements of 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. 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, 2005.
     Total estimated minimum long-term obligations at December 31, 2005 were as follows:
                 
    Natural    
Year   Gas   Coal
    (in thousands)
2006
  $ 123,447     $ 240,647  
2007
    71,482       92,694  
2008
    45,201        
2009
    18,886        
2010
    18,886        
2011 and thereafter
    204,030        
 
Total commitments
  $ 481,932     $ 333,341  
 
     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 $3.0 million, $2.0 million, and $2.2 million for 2005, 2004, and 2003, respectively. The Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term.

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NOTES (continued)
Gulf Power Company 2005 Annual Report
     At December 31, 2005, estimated minimum rental commitments for noncancelable operating leases were as follows:
                         
    Rail              
Year   Cars     Other     Total  
    (in thousands)  
2006
  $ 4,816     $ 59     $ 4,875  
2007
    4,105       61       4,166  
2008
    3,134       63       3,197  
2009
    2,101             2,101  
2010
    2,068             2,068  
2011 and thereafter
    4,170             4,170  
 
Total minimum payments
  $ 20,394     $ 183     $ 20,577  
 
     The Company and Mississippi Power jointly entered into operating lease agreements for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options.
     These railcar 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 $3.0 million in 2005 and $1.9 million in each of 2004 and 2003.
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, 2005, 269 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 for 2003 through 2005 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, 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 granted
    249,683       32.70  
Options canceled
    (2,131 )     29.08  
Options exercised
    (322,687 )     22.80  
 
Balance at December 31, 2005
    1,099,549     $ 27.07  
 
 
               
 
Options exercisable:
               
At December 31, 2003
    839,618          
At December 31, 2004
    715,570          
At December 31, 2005
    622,435          
 
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price  
    Range of Options  
    13-21     21-28     28-35  
 
Outstanding:
                       
Shares (in thousands)
    158       452       490  
Average remaining life (in years)
    4.2       6.3       8.6  
Average exercise price
  $ 17.11     $ 26.13     $ 31.13  
Exercisable:
                       
Shares (in thousands)
    158       381       84  
Average exercise price
  $ 17.11     $ 25.79     $ 29.67  
 

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NOTES (continued)
Gulf Power Company 2005 Annual Report
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2005 and 2004 are as follows:
                         
                    Net Income
                    After Dividends
    Operating   Operating   on Preferred and
Quarter Ended   Revenues   Income   Preference Stock
    (in thousands)
March 2005
  $ 224,597     $ 31,229     $ 14,646  
June 2005
    251,297       44,153       21,458  
September 2005
    344,080       68,571       37,197  
December 2005
    263,648       14,324       1,908  
 
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  
 
     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 2001-2005
Gulf Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands)
  $ 1,083,622     $ 960,131     $ 877,697     $ 820,467     $ 725,203  
Net Income after Dividends on Preferred and Preference Stock (in thousands)
  $ 75,209     $ 68,223     $ 69,010     $ 67,036     $ 58,307  
Cash Dividends on Common Stock (in thousands)
  $ 68,400     $ 70,000     $ 70,200     $ 65,500     $ 53,275  
Return on Average Common Equity (percent)
    12.59       11.83       12.42       12.72       12.51  
Total Assets (in thousands)
  $ 2,175,797     $ 2,111,877     $ 1,839,053     $ 1,816,889     $ 1,713,436  
Gross Property Additions (in thousands)
  $ 142,583     $ 161,205     $ 99,284     $ 106,624     $ 274,668  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 602,344     $ 592,172     $ 561,358     $ 549,505     $ 504,894  
Preferred and preference stock
    53,891       4,098       4,236       4,236       4,236  
Mandatorily redeemable preferred securities
                70,000       115,000       115,000  
Long-term debt payable to affiliated trusts
    72,166       72,166                    
Long-term debt
    544,388       550,989       515,827       452,040       467,784  
 
Total (excluding amounts due within one year)
  $ 1,272,789     $ 1,219,425     $ 1,151,421     $ 1,120,781     $ 1,091,914  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    47.3       48.6       48.8       49.0       46.2  
Preferred and preference stock
    4.2       0.3       0.4       0.4       0.4  
Mandatorily redeemable preferred securities
                6.1       10.3       10.5  
Long-term debt payable to affiliated trusts
    5.7       5.9                    
Long-term debt
    42.8       45.2       44.7       40.3       42.9  
 
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
    A+       A+       A+       A+       A+  
Preferred Stock/ Preference Stock —
                                       
Moody’s
  Baa1     Baa1     Baa1     Baa1     Baa1  
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
    354,466       343,151       341,935       333,757       327,128  
Commercial
    53,398       51,865       51,169       49,411       48,654  
Industrial
    298       285       285       281       270  
Other
    479       473       473       474       468  
 
Total
    408,641       395,774       393,862       383,923       376,520  
 
Employees (year-end)
    1,335       1,336       1,337       1,339       1,309  
 

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Gulf Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands) :
                                       
Residential
  $ 465,346     $ 401,382     $ 381,464     $ 365,693     $ 313,165  
Commercial
    273,114       232,928       218,928       207,960       188,759  
Industrial
    123,044       99,420       95,702       89,385       81,719  
Other
    3,355       3,140       3,080       2,798       948  
 
Total retail
    864,859       736,870       699,174       665,836       584,591  
Sales for resale — non-affiliates
    84,346       73,537       76,767       77,171       82,252  
Sales for resale — affiliates
    91,352       110,264       63,268       40,391       27,256  
 
Total revenues from sales of electricity
    1,040,557       920,671       839,209       783,398       694,099  
Other revenues
    43,065       39,460       38,488       37,069       31,104  
 
Total
  $ 1,083,622     $ 960,131     $ 877,697     $ 820,467     $ 725,203  
 
Kilowatt-Hour Sales (in thousands) :
                                       
Residential
    5,319,630       5,215,332       5,101,099       5,143,802       4,716,404  
Commercial
    3,735,776       3,695,471       3,614,255       3,552,931       3,417,427  
Industrial
    2,160,760       2,113,027       2,146,956       2,053,668       2,018,206  
Other
    22,730       22,579       22,479       21,496       21,208  
 
Total retail
    11,238,896       11,046,409       10,884,789       10,771,897       10,173,245  
Sales for resale — non-affiliates
    2,295,850       2,256,942       2,504,211       2,156,741       2,093,203  
Sales for resale — affiliates
    1,976,368       3,124,788       2,438,874       1,720,240       962,892  
 
Total
    15,511,114       16,428,139       15,827,874       14,648,878       13,229,340  
 
Average Revenue Per Kilowatt-Hour (cents) :
                                       
Residential
    8.75       7.70       7.48       7.11       6.64  
Commercial
    7.31       6.30       6.06       5.85       5.52  
Industrial
    5.69       4.71       4.46       4.35       4.05  
Total retail
    7.70       6.67       6.42       6.18       5.75  
Sales for resale
    4.11       3.42       2.83       3.03       3.58  
Total sales
    6.71       5.60       5.30       5.35       5.25  
Residential Average Annual Kilowatt-Hour Use Per Customer
    15,181       15,096       15,064       15,510       14,497  
Residential Average Annual Revenue Per Customer
  $ 1,328     $ 1,162     $ 1,126     $ 1,100     $ 963  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    2,712       2,712       2,786       2,809       2,188  
Maximum Peak-Hour Demand (megawatts) :
                                       
Winter
    2,124       2,061       2,494       2,182       2,106  
Summer
    2,433       2,421       2,269       2,454       2,223  
Annual Load Factor (percent)
    57.7       57.1       54.6       55.3       57.5  
Plant Availability Fossil-Steam (percent)
    89.7       92.4       90.7       90.6       90.1  
 
Source of Energy Supply (percent) :
                                       
Coal
    79.7       77.9       78.7       69.8       81.2  
Gas
    13.1       14.4       11.9       15.5       1.0  
Purchased power —
                                       
From non-affiliates
    2.8       4.5       3.2       4.6       6.5  
From affiliates
    4.4       3.2       6.2       10.1       11.3  
 
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 (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, 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, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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-257 to II-283) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power Company 2005 Annual Report
OVERVIEW
Business Activities
Mississippi Power Company (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 the Company’s 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 rising costs. These include costs related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration following Hurricane Katrina.
     Hurricane Katrina hit on August 29, 2005, causing substantial damage to the Company’s service territory as the worst natural disaster in the Company’s history. All of the Company’s 195,000 customers were without service immediately after the storm. Through a co-coordinated effort with Southern Company, as well as non-affiliates, the Company restored power to all who could receive it within twelve days. However, 19,200 customers remained unable to receive service as of December 31, 2005. The Company expects further rate proceedings in 2006 to recover the estimated $277 million in costs related to Hurricane Katrina and replenishment of the Company’s storm damage reserve. In 2004, the Company completed a successful retail rate proceeding designed to help provide future earnings stability. Appropriately balancing environmental expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future.
     In December 2005, the Company made its annual Performance Evaluation Plan (PEP) filing for the projected 2006 test period and requested a 5 percent increase in total retail revenues or $32 million increase in retail base revenues.
Key Performance Indicators
In striving to maximize shareholder value while providing cost effective energy to customers, the Company’s management continues to focus on several key indicators. These indicators are used to measure the Company’s performance for customers and employees. Recognizing the critical role in the Company’s success played by the Company employees, employee-related measures are a significant management focus. These measures include diversity and safety. The 2005 performance was at or above target for each of these employee performance standards. 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, 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 percent); service reliability, measured in outage minutes per customer (40 percent); and customer satisfaction, measured in surveys of residential customers (20 percent). The Company’s PEP performance score in 2005 was 8.44 out of 10, resulting in an 84 basis point increase to the Company’s retail allowed return on investment for 2006. See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” 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, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Management uses customer satisfaction surveys to evaluate the Company’s results. Peak season equivalent forced outage rate (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. Peak Season EFOR performance excludes the impact of Hurricane Katrina. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
     The Company’s 2005 results compared with its targets for some of these key indicators are reflected in the following chart.
                 
    2005   2005
Key Performance   Target   Actual
Indicator   Performance   Performance
Customer Satisfaction
  Top quartile in customer surveys   Top quartile
Plant Availability- Peak Season EFOR
  3.0% or less     1.51 %*
Net Income (in millions)
  $ 77.8     $ 73.8  
*   Excludes effects of Hurricane Katrina. Including Hurricane Katrina EFOR was 15.14%.
     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The Company’s performance in 2005 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 $73.8 million in 2005 compared to $76.8 million in 2004. The decrease in 2005 is primarily due to a $15.7 million decrease in retail base revenue due to the loss of customers as a result of Hurricane Katrina. Non-fuel related expenses increased $2.5 million primarily resulting from increased employee benefit expenses. Depreciation and amortization expenses decreased by $5.8 million due to the amortization of a regulatory liability related to Plant Daniel capacity, other revenues increased $1.2 million, wholesale base revenues increased $3.3 million, and dividends on preferred stock decreased $2.0 million as compared to 2004 as a result of the loss on redemption of preferred stock recognized in the third quarter of 2004.
     The net income after dividends on preferred stock of $76.8 million in 2004 increased when compared to $73.5 million in 2003 due to retail sales growth and higher non-territorial energy sales. 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 Company’s purchased power agreement with Dynegy, Inc. (Dynegy), 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 Public Service Commission (PSC). See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
RESULTS OF OPERATIONS
A condensed statement of income is as follows:
                                 
            Increase (Decrease)
    Amount   From Prior Year
    2005   2005   2004   2003
            (in thousands)        
Operating revenues
  $ 969,733     $ 59,407     $ 40,402     $ 45,759  
 
Fuel
    358,572       33,690       95,189       (52,700 )
Purchased power
    143,492       36,729       13,566       41,864  
Other operation and maintenance
    239,622       2,144       (62,198 )     67,663  
Depreciation and amortization
    33,549       (5,841 )     (16,310 )     (1,938 )
Taxes other than income taxes
    60,058       4,486       1,581       (1,527 )
 
Total operating expenses
    835,293       71,208       31,828       53,362  
 
Operating income
    134,440       (11,801 )     8,574       (7,603 )
Total other income and (expense)
    (12,525 )     2,417       1,898       7,525  
Less —
                               
Income taxes
    46,374       (4,292 )     5,351       (564 )
 
Net income
    75,541       (5,092 )     5,121       486  
 
Dividends on preferred stock
    1,733       (2,099 )     1,819        
 
Net income after dividends on preferred stock
  $ 73,808     $ (2,993 )   $ 3,302     $ 486  
 

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
Revenues
Details of the Company’s operating revenues in 2005 and the prior two years are as follows:
                         
    Amount
    2005   2004   2003
    (in thousands)
Retail — prior year
  $ 584,313     $ 516,301     $ 536,827  
Change in -
                       
Sales growth and weather
    (15,734 )     3,555       (367 )
Fuel cost recovery and other
    50,281       64,457       (20,159 )
 
Retail — current year
    618,860       584,313       516,301  
 
Sales for resale —
                       
Non-affiliates
    283,413       265,863       249,986  
Affiliates
    50,460       44,371       26,723  
 
Total sales for resale
    333,873       310,234       276,709  
 
Contract termination
                62,111  
 
Other electric operating revenues
    17,000       15,779       14,803  
 
Total electric operating revenues
  $ 969,733     $ 910,326     $ 869,924  
 
Percent change
    6.5 %     4.6 %     5.6 %
 
     Total retail revenues for 2005 increased 5.9 percent when compared to 2004 as a result of higher fuel revenue due to the increase in fuel cost. This increase in retail revenues was offset by reductions for the loss of customers in all major classes as a result of Hurricane Katrina. 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 the industrial class, also contributed to the increase. 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 (KWH) energy sales due to milder than normal weather in the Company’s service area and the sluggish economy.
     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 have no effect on net income. The fuel cost recovery and other revenues increased in 2005 when compared to 2004 as a result of higher fuel costs. In 2004, fuel cost recovery and other revenues increased as compared to 2003 due to an increase in fuel expenses resulting from 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. In 2005, total revenues from sales for resale to non-affiliates increased $17.5 million or 6.6 percent as compared to 2004. This increase primarily resulted from an increase in price per KWH resulting from higher fuel costs. 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 energy revenues, of which approximately $6 million was associated with increased KWH sales and $26.7 million was associated with higher fuel prices. Total revenues from sales for resale to non-affiliates increased in 2003 from 2002 as a result of increases in average sales price per KWH and increased KWH sales to wholesale non-affiliate customers. The increase in energy revenues was partially offset by an $18.3 million decrease in capacity revenues as a result of the termination of a contract with Dynegy in 2003.
     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, KWH sales to these utilities decreased 5.0 percent due to Hurricane Katrina in 2005, increased 3.3 percent in 2004, and remained relatively flat in 2003, with the related revenues increasing 16.2 percent, 12.4 percent, and 1.6 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to those experienced by the Company. 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 the energy. KWH sales to non-territorial customers decreased 41 percent as compared to 2004 primarily due to Hurricane Katrina.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
     Energy sales to affiliated companies within the Southern Company electric system as well as purchases of energy 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 Intercompany Interchange Contract (IIC), 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 marginal cost.
Energy Sales
KWH sales for 2005 and percent change by year were as follows:
                                 
             
    KWH   Percent Change        
    2005   2005   2004   2003
    (in millions)                        
Residential
    2,180       (5.1 )%     1.9 %     (1.9 )%
Commercial
    2,725       (8.2 )     1.9       0.4  
Industrial
    3,798       (10.3 )     3.0       (1.2 )
Other
    38       (5.8 )     1.0        
 
                               
Total retail
    8,741       (8.4 )     2.4       (0.9 )
Sales for resale
                               
Non-affiliated
    4,811       (20.2 )     2.6       9.2  
Affiliated
    897       (14.9 )     48.6       (55.3 )
 
                               
Total
    14,449       (13.1 )     4.5       (2.8 )
 
     Total retail KWH sales decreased in 2005 when compared to 2004 as the result of the loss of customers following Hurricane Katrina. Total retail KWH sales increased in 2004 when compared to 2003 as a result of economic recovery in the area which affected all customer classes, particularly the industrial class. Total retail KWH sales decreased in 2003 due to milder weather in 2003 when compared to 2002. Industrial sales also decreased in 2003 due to lower KWH sales and decreased fuel costs.
     The Company anticipates fairly strong growth over the next five years as the Company’s service area begins to recover from the effects of Hurricane Katrina. Retail sales are expected to grow at an annual rate of approximately 4.6 percent through 2010, as the rebuilding of residential homes and commercial businesses takes place. Various industrial expansions in oil and gas exploration, production, and refining are also expected to contribute to the growth.
Expenses
In 2005 and 2004, total operating expenses increased $71.2 million or 9.3 percent and $31.8 million or 4.3 percent, respectively, primarily as the result of increases in fuel and purchased power, administrative and general expenses, and taxes other than income. In 2003, operating expenses increased $53.4 million or 7.9 percent over the prior year. This increase was due primarily 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 –Performance Evaluation Plan” for further information.
     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 generating units. The amount and sources of generation, the average cost of fuel per net KWH generated, and the average cost of purchased power were as follows:
                         
    2005   2004   2003
 
Total generation (millions of KWHs)
    12,499       14,058       12,850  
Sources of generation (percent)
                       
Coal
    70       69       74  
Gas
    30       31       26  
Average cost of fuel per net KWH generated (cents)
    3.11       2.50       1.96  
Average cost of purchased power per net KWH (cents)
    5.44       3.28       2.51  
 
     Fuel expense increased $33.7 million in 2005 as compared to 2004. Approximately $71 million in additional fuel expenses resulted from higher coal, gas, transportation prices, and emission allowances, which were partially offset by a $37 million decrease resulting from unit outages that reduced generation. Fuel expense for 2004 increased $95 million as compared to 2003. Approximately $25 million of the increase was associated with increased generation and approximately $70 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
     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 increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term 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. See Note 1 to the financial statements under “Fuel Costs” for additional information.
     Purchased power expense increased $37 million, or 34.4 percent, in 2005 when compared to 2004. The increase is primarily the result of the reduction in generation due to the damage caused by Hurricane Katrina. In 2004, purchased power expense increased $13.6 million, or 14.6 percent when compared to 2003. The increase was primarily due to an increase in purchases from non-affiliates to meet increased load and offset higher priced self-generation resulting from increased fuel costs. In 2003, purchased power expense increased $41.9 million when compared to 2002. 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. 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 operations expense increased $7.9 million, or 4.9 percent, in 2005 as compared to 2004 primarily as a result a $5.2 million increase in employee benefit expenses, a $1.7 million increase in rent expense on the Plant Daniel combined cycle lease, and higher bad debt expense of $1 million primarily resulting from Hurricane Katrina. In 2004, other operations expense decreased $69.2 million, or 30 percent, and increased $71.2 million, or 45.0 percent, in 2003 due to approximately $11 million incurred in 2003 to restructure the Plant Daniel combined cycle lease agreement 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 – Performance Evaluation Plan” and “Operating Leases – Plant Daniel Combined Cycle Generating Units,” respectively, for additional information.
     Maintenance expense decreased $5.7 million, or 7.5 percent, in 2005 as a result of a $1.1 million decrease in long-term service agreement expense associated with the Plant Daniel combined cycle units as a result of fewer fired operating hours in 2005 when compared to 2004 and a $4.5 million decrease in maintenance expense associated with changes in scheduled maintenance as a result of restoration efforts. These restoration expenses have been deferred in accordance with a Mississippi PSC order. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. Maintenance expense increased $7.0 million, or 9.9 percent, in 2004 primarily resulting from higher operating hours at Plant Daniel and increased distribution line maintenance during 2004 as compared to 2003. In 2003, maintenance expense decreased $3.6 million, or 4.9 percent over the prior year, primarily due to 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
     Depreciation and amortization expense decreased $5.8 million in 2005 and $16.3 million in 2004 as compared to the prior years primarily as a result 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 – Performance Evaluation Plan” for additional information. In 2003, depreciation and amortization expense decreased $1.9 million due to the amortization related to the Company’s Environmental Compliance Overview Plan (ECO Plan) approved by the Mississippi PSC. The Company filed a depreciation study in 2005 with the Mississippi PSC and is awaiting approval. Depreciation expense would increase approximately $2.2 million annually effective January 1, 2006 if the depreciation study is approved as filed. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Compliance Overview Plan” for further information.
     In 2005, taxes other than income taxes increased 8.1 percent over the prior year due to a $2.9 million increase in ad valorem taxes and a $1.1 million increase in municipal franchise taxes. The retail portion, or approximately 82 percent, of the increase in ad valorem taxes is recoverable under the Company’s ad valorem tax cost recovery clause and, therefore, does not affect net income. The increase in municipal franchise taxes is directly related to the increase in total retail revenues. Taxes other than income taxes increased 2.9 percent in 2004 as compared to 2003 primarily due to additional municipal franchise taxes. Taxes other than income taxes decreased 2.8 percent in 2003 due to lower property taxes in 2003 as compared to 2002. 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 that is based on the recovery of costs. PEP is based on annual projected costs, including estimates for inflation. When inflation exceeds the projected costs used in rate regulation, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been significant.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in southeast 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 may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” 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 that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, 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 in the aftermath of Hurricane Katrina.
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 violations of the New Source Review (NSR)

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric, including three co-owned by the Company. 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 notices of violation relating to the Company’s Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in its notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled. See Note 3 to the financial statements under “Environmental Matters – New Source Review Actions.”
     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 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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The Mississippi Department of Environmental Quality (MDEQ) formally adopted the 2002 NSR rules effective July 28, 2005, but did not adopt the provisions vacated by the District of Columbia Circuit. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Mississippi’s implementation of such rules, as well as the outcome of any additional legal challenges, and therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

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Mississippi Power Company 2005 Annual Report
Environmental Statutes and Regulations
General
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. Applicable statutes 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 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 “Retail Regulatory Matters – Environmental Compliance Overview Plan” for additional information. Through 2005, the Company had invested approximately $46.8 million in capital projects to comply with these requirements, with annual totals of $4.0 million, $2.9 million, and $10.4 million for 2005, 2004, and 2003, respectively. Over the next decade the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $466 million, including $6.4 million, $27.0 million, and $40.1 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $7.7 million in reducing sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. During, 2005, the EPA’s fine particulate matter nonattainment designations also became effective for several areas across the United States. No areas within the Company’s service area, however, have been designated as nonattainment under either the eight-hour ozone standard or the fine particulate matter standard.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Mississippi are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and

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NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2, NOx, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release 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 the 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 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 Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Compliance Overview Plan” for additional information.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010-2012. The Company is continuing to evaluate future energy and emission profiles relative to

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the Climate VISION program and is analyzing voluntary programs to support the industry initiative.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005, are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $5.7 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $7.4 million, of which $4.4 million relates to sales inside the service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, Southern Power, and Southern Company Services, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

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     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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 cannot be determined at this time.
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 “Market-Based Rate Authority” and “Generation Interconnection Agreements” 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.
PSC Matters
Performance Evaluation Plan (PEP)
See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” for information on the Company’s base rates. 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.
     On December 1, 2005, the Company submitted its annual PEP filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, the Company has requested that the Mississippi PSC approve a temporary change to allow it to exceed this cap as a result of the ongoing effects of Hurricane Katrina. The Company has requested a 5 percent increase in total retail revenues or $32 million increase in retail base revenues to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.
Fuel Cost Recovery
The Company establishes annually a fuel cost recovery factor that is approved by the Mississippi PSC. Over the past year, the Company has continued to experience higher than expected fuel costs for coal and natural gas. The Company is required to file for an adjustment to the fuel cost recovery factor annually; such filing occurred in November 2005. As a result, the Mississippi PSC approved an increase in the fuel cost recovery factor effective January 2006 in an amount equal to 12 percent of total retail revenues. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on the Company’s revenues or net income.
Storm Damage Cost Recovery
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property. The Company’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.
     Hurricane Katrina hit the coast of Florida, Alabama, Mississippi, and Louisiana on August 29, 2005, causing substantial damage. The Company sustained significant damage to its distribution and transmission facilities. The Company’s Plant Watson was also damaged. Plant Watson has six generating units, including three gas-fired units totaling 262 megawatts (MW), two coal-fired units totaling 750 MW, and a 40 MW gas turbine. Both of the coal-fired units at the plant have been returned to service. The gas units operate primarily to serve summer peak loads. Repairs to the gas units are expected to be completed by June 1, 2006.
     As of December 31, 2005, approximately 19,200 of the Company’s customers remained unable to receive service. Prior to Hurricane Katrina, the Company had a balance of approximately $3 million in its property reserve. The Company currently estimates the total incremental cost of repairing the damages to its facilities and restoring service to customers will be approximately $277 million net of approximately $68 million of insurance proceeds. Business and government authorities are still reviewing redevelopment plans for portions of the severely damaged areas along the Mississippi shoreline. The ultimate impact of the redevelopment plans in these areas on the Company’s cost estimates cannot now be determined.
     The Mississippi PSC issued an Interim Accounting Order on October 21, 2005, requiring the Company to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. Total Hurricane Katrina costs incurred through December 31, 2005, include approximately $132.6 million of operations and maintenance expenditures and approximately $148.8 million of capital-related expenditures. On December 7, 2005, the Company filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. The Company is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to proposed state legislation to allow securitized financing and federal grant assistance. See Notes 1 and 3 to the financial statements under “Provision for Property Damage” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively, 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 pre-tax pension (income)/expense, before tax, of approximately $2.7 million, $0.6 million, and ($1.7) million, in 2005, 2004 and 2003 respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. Postretirement benefit costs for the Company were $5.3 million, $4.5 million, and $4.0 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefits are components 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 these matters.
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. Management has reviewed and discussed critical

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accounting policies and estimates 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. 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 (Statement No. 71), 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 and accounting principles generally accepted in the United States. 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 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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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 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 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 $27 million.
New Accounting Standards
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on the Company’s financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $9.5 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”
Stock Options
On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition remained stable at December 31, 2005. Net cash flow from operating activities totaled $42 million, $119 million, and $186 million for 2005, 2004, and 2003, respectively. The $77 million decrease for 2005 was primarily due to the storm damage costs related to Hurricane Katrina. These costs are expected to be recovered from customers in future periods and are included in the balance sheet under

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Deferred Property Damage. See FUTURE EARNINGS POTENTIAL “PSC Matters – Storm Damage Cost Recovery” for additional information.
     Significant changes in the balance sheet as of December 31, 2005 as compared to 2004 primarily relate to Hurricane Katrina storm restoration activities. These storm-related changes include increases in other accounts and notes receivable of $14.7 million, insurance receivable of $60 million, accumulated provision for uncollectible accounts of $1.5 million, prepaid income taxes of $32 million, notes payable of $202 million, affiliated accounts payable of $73.5 million, and accumulated deferred income taxes of $68.9 million. Current liabilities exceed current assets primarily due to the notes payable related to storm restoration activities. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Recovery” for additional information related to the deferral of the restoration costs, including both capital and operation and maintenance expenditures.
     The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 63.7 percent in 2004 to 64.3 percent at December 31, 2005. 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, continued storm damage restoration, and other purposes from sources similar to those used in the past. In addition, the Company is considering other financing options, such as securitization, for storm recovery costs. The amount, type, and timing of any future financings, if needed, will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors.
     The issuance of securities by the Company is subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933 (1933 Act). The amounts registered under the 1933 Act and the amounts authorized by the FERC, 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.
     To meet short-term cash needs and contingencies, the Company has various sources of liquidity. At the beginning of 2006, the Company had approximately $14.3 million of cash and cash equivalents and $276 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 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, 2005, the Company had $152 million outstanding in commercial paper notes.
     On February 24, 2006, the Company borrowed $100 million under a promissory note to Barclays Bank PLC due August 24, 2006. The borrowing bears interest at a variable rate based on LIBOR plus 0.3 percent, is unsecured, and may be prepaid at any time upon three days’ prior written notice. The promissory note includes representations and warranties, covenants, and events of default, including a maximum debt to total capitalization ratio of 65 percent. The promissory note also includes limitations on liens, consolidations, mergers, and sale of all or substantially all of the Company’s assets. The borrowing may become due and payable upon an event of default and expiration of any applicable cure periods. Events of default include: (i) nonpayment of obligations under the promissory note, (ii) failure to perform any covenant or agreement in the promissory note, (iii) material misrepresentations, (iv) failure to pay, or

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certain other defaults under, certain other indebtedness, and (v) certain bankruptcy or insolvency events.
Financing Activities
During 2005, 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.
     In June 2005, the Company issued $30 million of senior notes. The proceeds from this sale were used to redeem $30 million principal amount of first mortgage bonds due December 1, 2025. The related first mortgage bond indenture was legally defeased in June 2005 and retired in December 2005. As a result of this transaction, there are no longer any first mortgage bond liens on the Company’s property.
     In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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 Units.” 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 approximately $370 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, 2005, 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’s market risk exposures relative to interest rate changes have changed compared with the December 31, 2004, reporting period as a result of storm damage from Hurricane Katrina. The Company will manage this increased exposure through a number of means, including interest rate hedges, where appropriate.

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     The Company does not currently hedge interest rate risk. The weighted average interest rate on variable long-term debt at January 1, 2006, was 3.96 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 December 31, 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 December 31, 2005, 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, 2005, 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
    2005   2004
    (in thousands)
Contracts beginning of year
  $ 889     $ 2,470  
Contracts realized or settled
    (13,816 )     (9,181 )
Current period changes (a)
    40,033       7,600  
 
Contracts end of year
  $ 27,106     $ 889  
 
(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
  $ 27,645     $ 19,998     $ 7,647  
External sources
    (539 )     (539 )      
Models and other methods
                 
 
Contracts end of year
  $ 27,106     $ 19,459     $ 7,647  
 
     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, 2005, 2004, and 2003, these amounts were not material.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
    (in thousands)
Regulatory liabilities, net
  $ 27,463  
Other comprehensive income
    (342 )
Net income
    (15 )
 
Total fair value
  $ 27,106  
 
     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 $126 million for 2006, of which $30 million is related to Hurricane Katrina restoration, $112 million for 2007, and $139 million for 2008. Environmental expenditures included in these amounts are $6.4 million, $27.0 million, and $40.4 million for 2006, 2007, and 2008, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report
regulations; FERC rules and transmission regulations; load projections; storm impacts; 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, as well as the related interest, derivative obligations, 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 2005 Annual Report
Contractual Obligations
                                         
            2007-   2009-   After    
    2006   2008   2010   2010   Total
                    (in thousands)                
Long-term debt and preferred securities (a)
                                       
Principal
  $ 100,000     $     $ 40,000     $ 238,777     $ 378,777  
Interest
    14,137       28,274       26,418       287,922       356,751  
Commodity derivative obligations (b)
    969       105                   1,074  
Preferred stock dividends (c)
    1,728       3,456       3,456             8,640  
Operating leases
    33,927       65,371       61,908       32,513       193,719  
Purchase commitments (d)
                                       
Capital (e)
    126,000       251,000                   377,000  
Coal
    184,342       82,690                   267,032  
Natural gas (f)
    168,311       137,809       11,876       42,269       360,265  
Long-term service agreements
    13,198       22,796       23,219       95,538       154,751  
Post retirement benefit trust (g)
    260       520                   780  
 
Total
  $ 642,872     $ 592,021     $ 166,877     $ 697,019     $ 2,098,789  
 
     
(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, 2006, as reflected in the statements of capitalization.
 
(b)   For additional information, see Notes 1 and 6 to the financial statements herein.
 
(c)   Preferred stock does not mature; therefore, amounts are provided for the next five years only.
 
(d)   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 $240 million, $237 million, and $300 million, respectively.
 
(e)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
 
(f)   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, 2005.
 
(g)   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 2005 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, retail sales growth, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, 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 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, implementation of the Energy Policy Act of 2005, 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 FERC matters, and EPA civil actions;
 
  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, including rate cases relating to fuel cost recovery;
 
  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 Securities and Exchange Commission.
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, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)
Operating Revenues:
                       
Retail sales
  $ 618,860     $ 584,313     $ 516,301  
Sales for resale —
                       
Non-affiliates
    283,413       265,863       249,986  
Affiliates
    50,460       44,371       26,723  
Contract termination
                62,111  
Other revenues
    17,000       15,779       14,803  
 
Total operating revenues
    969,733       910,326       869,924  
 
Operating Expenses:
                       
Fuel
    358,572       324,882       229,693  
Purchased power —
                       
Non-affiliates
    32,208       33,528       18,523  
Affiliates
    111,284       73,235       74,674  
Other operations —
                       
Plant Daniel capacity
                60,300  
Other
    168,355       160,477       169,333  
Maintenance
    71,267       77,001       70,043  
Depreciation and amortization
    33,549       39,390       55,700  
Taxes other than income taxes
    60,058       55,572       53,991  
 
Total operating expenses
    835,293       764,085       732,257  
 
Operating Income
    134,440       146,241       137,667  
Other Income and (Expense):
                       
Interest income
    1,718       777       617  
Interest expense
    (11,230 )     (11,776 )     (14,369 )
Interest expense to affiliate trust
    (2,598 )     (1,948 )      
Distributions on mandatorily redeemable preferred securities
          (630 )     (2,520 )
Other income (expense), net
    (415 )     (1,365 )     (568 )
 
Total other income and (expense)
    (12,525 )     (14,942 )     (16,840 )
 
Earnings Before Income Taxes
    121,915       131,299       120,827  
Income taxes
    46,374       50,666       45,315  
 
Net Income
    75,541       80,633       75,512  
Dividends on Preferred Stock
    1,733       3,832       2,013  
 
Net Income After Dividends on Preferred Stock
  $ 73,808     $ 76,801     $ 73,499  
 
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, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)
Operating Activities:
                       
Net income
  $ 75,541     $ 80,633     $ 75,512  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    63,319       60,260       60,226  
Deferred income taxes and investment tax credits, net
    118,316       44,424       (8,562 )
Plant Daniel capacity
    (25,125 )     (16,508 )     60,300  
Pension, postretirement, and other employee benefits
    2,938       (1,084 )     (1,014 )
Tax benefit of stock options
    3,723       1,532       3,018  
Other, net
    1,493       (1,823 )     1,816  
Changes in certain current assets and liabilities —
                       
Receivables
    (107,836 )     (26,250 )     20,864  
Fossil fuel stock
    (25,745 )     5,528       2,070  
Materials and supplies
    (6,234 )     (3,768 )     (1,607 )
Prepaid income taxes
    (40,059 )     3,419       (5,638 )
Other current assets
    (2,498 )     (2,018 )     6,807  
Hurricane Katrina accounts payable
    (82,102 )            
Other accounts payable
    40,255       (5,555 )     (20,602 )
Accrued taxes
    4,001       151       (8,976 )
Accrued compensation
    674       82       (2,568 )
Over recovered regulatory clause revenues
    20,831       (25,761 )     694  
Other current liabilities
    441       6,052       3,264  
 
Net cash provided from operating activities
    41,933       119,314       185,604  
 
Investing Activities:
                       
Property additions
    (158,084 )     (72,066 )     (72,134 )
Cost of removal net of salvage
    (26,140 )     (3,189 )     (5,811 )
Construction payables
    16,417       1,243       (1,414 )
Other
    (2,655 )     (2,066 )      
 
Net cash used for investing activities
    (170,462 )     (76,078 )     (79,359 )
 
Financing Activities:
                       
Increase in notes payable, net
    202,124              
Proceeds —
                       
Senior notes
    30,000       40,000       90,000  
Preferred stock
          30,000        
Capital contributions from parent company
    (25 )     1,791       4,912  
Redemptions —
                       
First mortgage bonds
    (30,000 )           (33,350 )
Pollution control bonds
                (850 )
Senior notes
          (80,000 )     (86,628 )
Preferred stock
          (28,388 )      
Payment of preferred stock dividends
    (1,733 )     (1,829 )     (2,013 )
Payment of common stock dividends
    (62,000 )     (66,200 )     (66,000 )
Other
    (2,481 )     (785 )     (5,891 )
 
Net cash provided from (used for) financing activities
    135,885       (105,411 )     (99,820 )
 
Net Change in Cash and Cash Equivalents
    7,356       (62,175 )     6,425  
Cash and Cash Equivalents at Beginning of Year
    6,945       69,120       62,695  
 
Cash and Cash Equivalents at End of Year
  $ 14,301     $ 6,945     $ 69,120  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest
  $ 13,499     $ 12,084     $ 17,334  
Income taxes (net of refunds)
    (40,801 )     6,654       60,618  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Mississippi Power Company 2005 Annual Report
                 
    2005     2004  
    (in thousands)  
Assets
               
Current Assets:
               
Cash and cash equivalents
  $ 14,301     $ 6,945  
Receivables —
               
Customer accounts receivable
    36,747       32,978  
Unbilled revenues
    20,267       20,803  
Under recovered regulatory clause revenues
    120,653       32,499  
Other accounts and notes receivable
    21,503       8,881  
Insurance receivable
    60,163        
Affiliated companies
    19,595       15,769  
Accumulated provision for uncollectible accounts
    (2,321 )     (774 )
Fossil fuel stock, at average cost
    45,449       19,704  
Materials and supplies, at average cost
    33,673       27,438  
Assets from risk management activities
    20,429       4,471  
Prepaid income taxes
    42,278       5,814  
Other
    12,625       12,741  
 
Total current assets
    445,362       187,269  
 
Property, Plant, and Equipment:
               
In service
    1,987,294       1,882,542  
Less accumulated provision for depreciation
    803,754       697,862  
 
 
    1,183,540       1,184,680  
Construction work in progress
    52,225       27,961  
 
Total property, plant, and equipment
    1,235,765       1,212,641  
 
Other Property and Investments
    6,825       6,402  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    9,863       10,668  
Prepaid pension costs
    17,264       19,158  
Deferred property damage
    209,324        
Other
    56,866       42,975  
 
Total deferred charges and other assets
    293,317       72,801  
 
Total Assets
  $ 1,981,269     $ 1,479,113  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Mississippi Power Company 2005 Annual Report
                 
    2005     2004  
    (in thousands)  
Liabilities and Stockholder’s Equity
               
Current Liabilities:
               
Notes payable
  $ 202,124     $  
Accounts payable —
               
Affiliated
    122,899       19,568  
Other
    89,598       52,688  
Customer deposits
    7,298       9,053  
Accrued taxes —
               
Income taxes
    17,736       396  
Other
    48,296       44,285  
Accrued interest
    3,408       1,731  
Accrued compensation
    24,587       23,913  
Regulatory clauses over recovery
    26,188       5,356  
Plant Daniel capacity
    13,008       25,125  
Other
    40,334       27,067  
 
Total current liabilities
    595,476       209,182  
 
Long-term Debt (See accompanying statements)
    242,548       242,498  
 
Long-term Debt Payable to Affiliated Trust (See accompanying statements)
    36,082       36,082  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    266,629       167,345  
Deferred credits related to income taxes
    19,003       20,261  
Accumulated deferred investment tax credits
    17,465       18,654  
Employee benefit obligations
    58,318       57,275  
Other cost of removal obligations
    81,284       76,228  
Other regulatory liabilities
    13,411       23,154  
Other
    57,113       49,817  
 
Total deferred credits and other liabilities
    513,223       412,734  
 
Total Liabilities
    1,387,329       900,496  
 
Preferred Stock (See accompanying statements)
    32,780       32,780  
 
Common Stockholder’s Equity (See accompanying statements)
    561,160       545,837  
 
Total Liabilities and Stockholder’s Equity
  $ 1,981,269     $ 1,479,113  
 
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, 2005 and 2004
Mississippi Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
    (in thousands)     (percent of total)  
Long-Term Debt:
                               
First mortgage bonds — 6.875% due 2025
  $     $ 30,000                  
 
Long-term notes payable —
                               
5.4% to 5.625% due 2033-2035
    120,000       90,000                  
Adjustable rates (4.64% at 1/1/06) due 2009
    40,000       40,000                  
 
Total long-term notes payable
    160,000       130,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds — non-collateralized:
                               
Variable rates (3.45% to 3.87% at 1/1/06) due 2020-2028
    82,695       82,695                  
 
Unamortized debt premium (discount), net
    (147 )     (197 )                
 
Total long-term debt (annual interest requirement — $11.5 million)
    242,548       242,498       27.8 %     28.3 %
 
Long-term Debt Payable to Affiliated Trust:
                               
7.20% due 2041 (annual interest requirement — $2.6 million)
    36,082       36,082       4.1       4.2  
 
Cumulative Preferred Stock:
                               
$100 par value
                               
Authorized — 1,244,139 shares
                               
Outstanding — 334,210 shares
                               
4.40% to 5.25% (annual dividend requirement — $1.7 million)
    32,780       32,780       3.8       3.8  
 
Common Stockholder’s Equity:
                               
Common stock, without par value —
                               
Authorized - 1,130,000 shares
                               
Outstanding - 1,121,000 shares
    37,691       37,691                  
Paid-in capital
    299,536       295,837                  
Retained earnings
    227,701       215,893                  
Accumulated other comprehensive income (loss)
    (3,768 )     (3,584 )                
 
Total common stockholder’s equity
    561,160       545,837       64.3       63.7  
 
Total Capitalization
  $ 872,570     $ 857,197       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, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report
                                         
                          Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
    (in thousands)  
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  
Net income after dividends on preferred stock
                73,808             73,808  
Capital contributions from parent company
          3,699                   3,699  
Other comprehensive income (loss)
                      (184 )     (184 )
Cash dividends on common stock
                (62,000 )           (62,000 )
 
Balance at December 31, 2005
  $ 37,691     $ 299,536     $ 227,701     $ (3,768 )   $ 561,160  
           
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report
                         
    2005     2004     2003  
Net income after dividends on preferred stock
  $ 73,808     $ 76,801     $ 73,499  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(167), $(1,131) and $(123), respectively
    (269 )     (1,825 )     (198 )
Change in fair value of marketable securities, net of tax of $49
          80        
Changes in fair value of qualifying hedges, net of tax of $53 and $(184), respectively
    85       (297 )      
Less: Reclassification adjustment for amounts included in net income, net of tax of $(49)
          (80 )      
 
Total other comprehensive income (loss)
    (184 )     (2,122 )     (198 )
 
Comprehensive Income
  $ 73,624     $ 74,679     $ 73,301  
 
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2005 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 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 southeast 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). 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 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. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
      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 with current year presentation.
      Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were 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 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 $51.6 million, $45.3 million, and $46.1 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, and management believes they are reasonable.
      The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in the last two years, assistance for storm restoration has caused an increase in these activities. The total amount of storm restoration provided to Alabama Power, Georgia Power, and Gulf Power in 2004 and 2005 was $3.3 million and $1.0 million, respectively. These activities were billed at cost. The Company received storm restoration assistance from other Southern Company subsidiaries in 2005 totaling $73.5 million.
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     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 $8.2 million, $7.2 million, and $6.6 million in 2005, 2004, and 2003, 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 $18.4 million, $17.8 million, and $17.7 million in 2005, 2004, and 2003, respectively. See Notes 4 and 5 for additional information on certain deferred tax liabilities payable to affiliates.
     The retail operating companies, including the Company, and Southern Power 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.
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:
                     
  2005   2004     Note
  (in thousands)    
Hurricane Katrina
  $ 209,324     $     (i)
Property Damage
    (500 )     (5,035 )   (g)
Deferred income tax charges
    10,443       11,358     (a)
Property tax
    15,148       11,199     (b)
Vacation pay
    6,954       6,125     (c)
Loss on reacquired debt
    10,381       9,437     (d)
Loss on redeemed preferred stock
    914       1,086     (e)
Other regulatory assets
    405       460      
Fuel-hedging assets
    232       2,666     (f)
Asset retirement obligations
    10,668       1,398     (a)
Deferred income tax credits
    (20,559 )     (21,789 )   (a)
Other cost of removal obligations
    (81,284 )     (76,228 )   (a)
Plant Daniel capacity
    (18,667 )     (43,792 )   (h)
Fuel-hedging liabilities
    (27,695 )     (4,027 )   (f)
Other liabilities
    (660 )     (142 )   (g)
 
Total
  $ 115,104     $ (107,284 )    
 
 
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 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 50 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 as approved by the Mississippi PSC.
 
(h)   Amortized over a four-year period ending in 2007.
 
(i)   For additional information, see Note 3 under “Retail Regulatory Matters — Storm Damage Cost Recovery.”
     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
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Mississippi Power Company 2005 Annual Report
not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are to be reflected in rates. See Note 3 herein under “Retail Regulatory Matters — Storm Damage Cost Recovery.”
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 these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery factor annually.
     The Company has a diversified base of customers. For years ended December 31, 2005 and December 31, 2004, 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. Fuel costs also included gains and/or losses from fuel hedging programs as approved by the Mississippi PSC.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction for projects over $10 million.
     The Company’s property, plant, and equipment consisted of the following at December 31 (in thousands):
                 
    2005     2004  
Generation
  $ 833,598     $ 824,755  
Transmission
    390,961       377,717  
Distribution
    624,769       547,231  
General
    137,966       132,839  
 
Total plant in service
  $ 1,987,294     $ 1,882,542  
 
     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.
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 2005, 2004, and 2003. Depreciation studies are conducted periodically to update the composite rates. The Company filed a study in 2005 with the Mississippi PSC and is awaiting approval. 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

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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 January 2006, the Mississippi PSC issued an accounting order directing the Company to exclude from its calculation of depreciation expense approximately $1.2 million related to capitalized Hurricane Katrina costs since these costs will be recovered separately.
     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 reduce depreciation and amortization expenses 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, which 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 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. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because of the timing of their requirements was dependent on future events. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in 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 or Interpretation No. 47.
     The Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, the Company also recorded additional asset retirement obligations (and assets) of $9.5 million, primarily related to asbestos. 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 assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.
     Details of the asset retirement obligations included in the balance sheets are as follows:
                 
    2005     2004  
    (in millions)  
Balance, beginning of year
  $ 5.5     $ 2.5  
Liabilities incurred
    9.5        
Liabilities settled
           
Accretion
    0.4       0.2  
Cash flow revisions
          2.8  
 
Balance, end of year
  $ 15.4     $ 5.5  
 
     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $14.1 million.

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Mississippi Power Company 2005 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 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.
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 $1.5 million in 2005, $4.6 million in 2004, and $2.5 million in 2003. See Note 3 under “Storm Damage Cost Recovery” for additional information regarding the depletion of these reserves following Hurricane Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which may be approved by the Mississippi PSC to replenish these reserves.
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. The Company filed its 2006 ECO Plan in February 2006, which if approved as filed, is anticipated to result in a slight decrease in customer prices.
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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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.

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Mississippi Power Company 2005 Annual Report
     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on net income is as follows:
                         
    As   Option   Pro
    Reported   Impact   Forma
    (in thousands)
2005
  $ 73,808     $ (648 )   $ 73,160  
2004
    76,801       (682 )     76,119  
2003
    73,499       (758 )     72,741  
 
     The estimated fair values of stock options granted in 2005, 2004, and 2003 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:
                         
    2005   2004   2003
 
Interest rate
    3.9 %     3.1 %     2.7 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.9 %     19.6 %     23.6 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
 
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 or are recoverable through the Mississippi PSC approved fuel hedging program as discussed below. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, as appropriate until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges 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 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 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:
               
2005
  $ 278,630     $ 273,278  
2004
  $ 278,580     $ 282,884  
 
     The fair values were based on either closing market price or closing price of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, 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.

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Mississippi Power Company 2005 Annual Report
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established a wholly-owned trust established to issue preferred securities. However, 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 in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. 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 Mississippi PSC and the FERC. For the year ending December 31, 2006, postretirement trust contributions are expected to total approximately $260,000.
     The measurement date for plan assets and obligations is September 30 of each year presented.
Pension Plans
The total accumulated benefit obligation for the pension plans was $235 million and $211 million for 2005 and 2004, 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  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 232,658     $ 207,689  
Service cost
    6,566       6,153  
Interest cost
    13,089       12,249  
Benefits paid
    (10,703 )     (10,564 )
Actuarial loss and employee transfers
    12,080       16,342  
Amendments
    1,347       789  
 
Balance at end of year
  $ 255,037     $ 232,658  
 
                 
    Plan Assets  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 222,543     $ 210,285  
Actual return on plan assets
    33,654       20,419  
Benefits paid
    (9,497 )     (8,985 )
Employee transfers
    (429 )     824  
 
Balance at end of year
  $ 246,271     $ 222,543  
 
     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $234.3 million and $20.8 million, respectively. All plan assets are related to the qualified plan.

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Mississippi Power Company 2005 Annual Report
     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     2005     2004  
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
                 
    2005     2004  
    (in thousands)  
Funded status
  $ (8,767 )   $ (10,115 )
Unrecognized transition obligation
    (545 )     (1,090 )
Unrecognized prior service cost
    14,288       14,423  
Unrecognized net gain (loss)
    3,915       8,315  
 
Prepaid pension asset, net
  $ 8,891     $ 11,533  
 
     The prepaid asset, net is reflected in the balance sheets in the following line items:
                 
    2005     2004  
    (in thousands)  
Prepaid pension asset
  $ 17,264     $ 19,158  
Employee benefit obligations
    (16,357 )     (15,394 )
Other property and investment- other
    2,224       2,445  
Accumulated other comprehensive income
    5,760       5,324  
 
Prepaid pension, net
  $ 8,891     $ 11,533  
 
     Components of the pension plans’ net periodic cost were as follows:
                         
    2005     2004     2003  
    (in thousands)  
Service cost
  $ 6,566     $ 6,153     $ 5,607  
Interest cost
    13,089       12,249       11,965  
Expected return on plan assets
    (18,437 )     (18,325 )     (18,329 )
Recognized net (gain) loss
    526       865       (1,847 )
Net amortization
    937       (361 )     862  
 
Net pension (income) expense
  $ 2,681     $ 581     $ (1,742 )
 
     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, 2005, estimated benefit payments were as follows:
         
    2005
    (in thousands)
2006
  $ 11,112  
2007
    11,138  
2008
    11,288  
2009
    11,648  
2010
    11,987  
2011 to 2015
  $ 70,609  
 

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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  
    2005     2004  
   
    (in thousands)  
Balance at beginning of year
  $ 75,435     $ 72,186  
Service cost
    1,427       1,330  
Interest cost
    4,242       4,015  
Benefits paid
    (3,937 )     (3,364 )
Actuarial (gain) loss
    9,315       1,268  
 
Balance at end of year
  $ 86,482     $ 75,435  
 
                 
    Plan Assets  
    2005     2004  
   
    (in thousands)  
Balance at beginning of year
  $ 20,183     $ 18,185  
Actual return on plan assets
    2,462       1,868  
Employer contributions
    4,051       3,494  
Benefits paid
    (3,937 )     (3,364 )
 
Balance at end of year
  $ 22,759     $ 20,183  
 
     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     2005     2004  
 
Domestic equity
    28 %     31 %     27 %
International equity
    18       18       15  
Fixed income
    35       36       45  
Real estate
    11       10       8  
Private equity
    8       5       5  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
                 
    Accrued Costs  
    2005     2004  
   
    (in thousands)  
Funded status
  $ (63,723 )   $ (55,253 )
Unrecognized transition obligation
    2,543       2,889  
Unrecognized prior service cost
    1,398       1,504  
Unrecognized net gain
    26,919       19,211  
Fourth quarter contributions
    902       779  
 
Accrued liability recognized in the Balance Sheets
  $ (31,961 )   $ (30,870 )
 
     Components of the postretirement plans’ net periodic cost were as follows:
                         
    Net Periodic Costs  
   
    2005     2004     2003  
   
    (in thousands)  
Service cost
  $ 1,427     $ 1,330     $ 1,149  
Interest cost
    4,242       4,015       3,898  
Expected return on Plan assets
    (1,563 )     (1,716 )     (1,598 )
Transition obligation
    346       346       346  
Prior service cost
    106       106       106  
Recognized net loss
    706       408       116  
 
Net postretirement cost
  $ 5,264     $ 4,489     $ 4,017  
 
     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 and for the year ended December 31, 2005 by approximately $0.5 million and $1.2 million, respectively, and is expected to have a similar impact on future expenses.

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     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)  
2006
  $ 4,092     $ (418 )   $ 3,674  
2007
    4,433       (508 )     3,925  
2008
    4,779       (576 )     4,203  
2009
    5,186       (627 )     4,559  
2010
    5,521       (687 )     4,834  
2011 to 2015
  $ 31,273       $(4,775 )   $ 26,498  
 
Actuarial Assumptions
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 benefits plans were as follows:
                         
    2005     2004     2003  
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00       3.50       3.75  
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of one percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows :
                 
    1 Percent  
    Increase     Decrease  
   
    (in thousands)  
Benefit obligation
  $ 6,456     $ 5,815  
Service and interest costs
    498       392  
 
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 2005, 2004, and 2003 were $2.9 million, $2.8 million, and $2.7 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 such as opacity and other air quality standards, 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 pending or potential 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.

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Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against 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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric, including three co-owned by the Company. 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 notices of violation relating to the Company’s Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in its notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction and the EPA has not refiled. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
     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 matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
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, 2004, and 2005 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 Company are expected to be recovered through the Company’s ECO Plan.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of

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the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $5.7 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $7.4 million, of which $4.4 million relates to sales inside the service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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. 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.

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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.
     To date, the Company has entered into agreements with plaintiffs in approximately 90 percent of the actions pending against the Company to clarify the Company’s easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit) and dismissals of the related cases are in progress. These agreements have not had any material impact on the Company’s financial statements.
     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 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. In January 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
Performance Evaluation Plan
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 2005, the Company submitted its annual PEP filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, the Company has requested that the Mississippi PSC approve a temporary change to allow them to exceed this cap as a result of the ongoing effects of Hurricane Katrina. The Company has requested a 5 percent increase in total retail revenues or $32 million retail base revenue increase to become

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effective in April 2006 if approved. Hearings are scheduled for March 2, 2006. The final outcome of this matter cannot now be determined.
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 2005 ECO Plan filing was approved, as filed, by the Mississippi PSC on April 18, 2005 and resulted in a slight increase in rates effective May 2005.
Storm Damage Cost Recovery
The Company maintains a reserve 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. The Company’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.
     In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The Company sustained significant damage to its distribution and transmission facilities. The Company’s Plant Watson was also damaged. Plant Watson has six generating units, including three gas-fire units totaling 262 megawatts (MW), two coal-fired units totaling 750 MW, and a 40 MW gas turbine. Both of the coal-fired units at the plant have been returned to service. The gas units operate primarily to serve summer peak loads. Repairs to the gas units are expected to be completed by June 1, 2006.
     Prior to Hurricane Katrina, the Company had a balance of approximately $3 million in its property reserve. Incremental Hurricane Katrina restoration costs are currently estimated to total approximately $277 million, net of approximately $68 million of insurance proceeds. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 of the Company’s customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.
     The Mississippi PSC issued an Interim Accounting Order on October 21, 2005, requiring the Company to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital related expenditures. Total Hurricane Katrina costs incurred through December 31, 2005 include approximately $132.6 million of operations and maintenance expenditures and approximately $148.8 million of capital-related expenditures. The cash portions are included in the Statement of Cash Flow under Hurricane Katrina Accounts Payable, Property Additions, and Cost of Removal, net of Salvage and totaled approximately $82.1 million, $81.7 million, and $18.4 million, respectively. On December 7, 2005 the Company filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. The Company is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to proposed state legislation to allow securitized financing and federal grant assistance.
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.

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Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 with a total capacity of 1,000 MW at Plant Daniel, which is located in Mississippi and operated by the Company.
     At December 31, 2005, the Company’s percentage ownership and investment in these jointly owned facilities were as follows:
                         
Generating   Percent   Gross     Accumulated  
Plant   Ownership   Investment     Depreciation  
   
    (in thousands)  
Greene County
                       
Units 1 and 2
    40 %   $ 73,722     $ 40,172  
 
Daniel
                       
Units 1 and 2
    50 %   $ 255,712     $ 129,510  
 
     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 and combined income tax returns for the State of Alabama and the State of Mississippi. Under a joint consolidated income tax allocation agreement, 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.
     At December 31, 2005, the tax-related regulatory assets and liabilities were $10.4 million and $20.6 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:
                         
    2005     2004     2003  
   
    (in thousands)  
Federal —
                       
Current
  $ (61,933 )   $ 3,700     $ 46,116  
Deferred
    102,659       40,350       (6,166 )
 
 
    40,726       44,050       39,950  
 
State —
                       
Current
    (10,009 )     2,542       7,761  
Deferred
    15,657       4,074       (2,396 )
 
 
    5,648       6,616       5,365  
 
Total
  $ 46,374     $ 50,666     $ 45,315  
 
     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:
                 
    2005     2004  
   
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 269,188     $ 224,353  
Basis differences
    8,630       14,092  
Fuel clause under recovered
    41,627       8,696  
Other
    59,883       22,382  
 
Total
    379,328       269,523  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    13,642       7,639  
Other property basis differences
    9,244       9,762  
Pension and other benefits
    13,473       12,756  
Property insurance
    3,618       4,108  
Unbilled fuel
    7,660       6,225  
Other comprehensive loss
    2,441       2,322  
Other
    44,961       62,651  
 
Total
    95,039       105,463  
 
Total deferred tax liabilities, net
    284,289       164,060  
Portion included in prepaid (accrued) income taxes, net
    (17,660 )     3,285  
 
Accumulated deferred income taxes in the balance sheets
  $ 266,629     $ 167,345  
 

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     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, 2005, 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:
                         
    2005     2004     2003  
         
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    3.0       3.3       2.9  
Non-deductible book Depreciation
    0.5       0.4       0.4  
Other
    (0.5 )     (0.1 )     (0.8 )
         
Effective income tax rate
    38.0 %     38.6 %     37.5 %
         
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 in the balance sheets as Long-term Debt Payable to Affiliated Trust (including Securities Due Within One Year). 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, 2005, 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, 2005 was $82.7 million.
Assets Subject to Lien
In June 2005, the Company’s first mortgage bond indenture was defeased. In December 2005, the remaining outstanding first mortgage bonds were retired by the first mortgage bond trustee. As a result, there are no longer any liens on the Company’s property and the Company no longer has to comply with the covenants and restrictions of the first mortgage bond indenture.
Bank Credit Arrangements
At the beginning of 2006, the Company had total committed credit agreements with banks for approximately $326 million, and $276 million remained unused. Of the total, $101 million expires in 2006 and $225 million in 2008. The Company expects to renew its credit facilities, as needed, prior to expiration. Some of the 2006 agreements allow short-term borrowings to be converted into term loans.
     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 1/8 of 1 percent or less for the Company. Compensating balances are not legally restricted from withdrawal.
     This $276 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2005, the Company had $152 million outstanding in commercial notes. The credit arrangements also provide support to the Company’s variable daily rate tax-exempt pollution control bonds totaling $40 million.

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     During 2005, the peak amount outstanding for short-term debt was $154 million and the average amount outstanding was $42 million. The average annual interest rate on short-term debt was 3.85 percent in 2005.
Financial Instruments
The Company also 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 2005, 2004, or 2003.
     In addition, at the instruction of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2005, exposure from these activities was not material to the Company’s financial statements.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts
 
    (in thousands)
Regulatory liabilities, net
  $ 27,463  
Other comprehensive income
    (342 )
Net income
    (15 )
 
Total fair value
  $ 27,106  
 
     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 2006, approximately $0.3 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 2008.
7.   COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated to total $126 million in 2006, of which $30 million is related to Hurricane Katrina restoration, $112 million in 2007, and $139 million in 2008. 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, 2005, 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. The LTSA provides 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 $7.9 million, $9.0 million, and $6.0 million for 2005, 2004, and 2003, respectively, which is included in maintenance expense in the statements of income. Remaining payments to GE under this agreement are currently estimated to total $152 million over the next 12 years. However, the LTSA contains various cancellation provisions at the option of the Company.

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NOTES (continued)
Mississippi Power Company 2005 Annual Report
     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 $3.0 million over the remaining term of the agreement, which is approximately fifteen months. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to ABB prior to the performance of any planned maintenance are recorded as a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.
Fuel 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 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, 2005. Total estimated minimum long-term obligations at December 31, 2005 were as follows:
                 
Year   Natural Gas     Coal  
   
    (in thousands)  
2006
  $ 168,311     $ 184,342  
2007
    86,978       64,138  
2008
    50,831       18,552  
2009
    5,938        
2010
    5,938        
2011 and thereafter
    42,269        
 
Total commitments
  $ 360,265     $ 267,032  
 
     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 the other retail operating companies, Southern Power, and Southern Company Gas. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company Gas as a contracting party under these agreements.

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NOTES (continued)
Mississippi Power Company 2005 Annual Report
Operating Leases
Railcar Leases
The Company and Gulf Power have jointly entered into operating lease agreements for the use of 745 aluminum railcars. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. The Company also has multiple operating lease agreements for the use of an additional 120 aluminum railcars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel.
     The Company’s share (50 percent) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $3.0 million in 2005 and $1.9 million in 2004 and 2003. The Company’s annual lease payments for 2006 through 2010 will average approximately $3.2 million and after 2011, lease payments total in aggregate approximately $4.2 million.
     In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson. The Company’s share (50 percent at Plant Daniel and 100 percent at Plant Watson) of these leases was charged to fuel handling expense in the amount of $611,000 in 2005. The Company’s annual lease payments for 2006 through 2010 will average approximately $693,000 and after 2011, lease payments total in aggregate approximately $52,000.
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 – Performance Evaluation Plan” for a description of 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 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 $370 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 $11 million and $13 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31, 2005 and 2004, respectively. In 2003, approximately $11 million in lease termination costs and were included in other operation expense. Lease expenses were $27 million, $27 million, and $26 million in 2005, 2004, and 2003, respectively.

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NOTES (continued)
Mississippi Power Company 2005 Annual Report
     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, 2005, are as follows:
         
Year   Lease Payments
    (in thousands)
2006
  $ 28,824  
2007
    28,718  
2008
    28,616  
2009
    28,504  
2010
    28,398  
2011 and thereafter
    28,291  
 
Total commitments
  $ 171,351  
 
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, 2005, 275 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 2003 to 2005 for the options granted to the Company’s employees under the stock option plan is summarized below:
                 
      Average
    Shares   Option
    Subject   Price
    to Option   per Share
 
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 granted
    272,813       32.71  
Options canceled
    (1,314 )     29.81  
Options exercised
    (422,472 )     21.67  
 
Balance at December 31, 2005
    1,444,438     $ 26.86  
 
 
               
Options exercisable:
               
At December 31, 2003
    794,374          
At December 31, 2004
    1,019,627          
At December 31, 2005
    920,511          
 

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NOTES (continued)
Mississippi Power Company 2005 Annual Report
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price
    Range of Options
    13-21   21-28   28-35
 
Outstanding:
                       
Shares (in thousands)
    191       679       575  
Average remaining life (in years)
    4.1       5.5       8.2  
Average exercise price
  $ 17.67     $ 25.93     $ 31.02  
Exercisable:
                       
Shares (in thousands)
    191       594       136  
Average exercise price
  $ 17.67     $ 25.64     $ 29.66  
 
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2005 and 2004 are as follows:
                         
                    Net Income
                    After Dividends
    Operating   Operating   On Preferred
Quarter Ended   Revenues   Income   Stock
    (in thousands)
March 2005
  $ 215,210     $ 31,902     $ 16,947  
June 2005
    248,576       43,061       25,632  
September 2005
    277,907       51,975       28,244  
December 2005
    228,040       7,502       2,985  
 
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  
 
     The Company’s business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Mississippi Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands)
  $ 969,733     $ 910,326     $ 869,924     $ 824,165     $ 796,065  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 73,808     $ 76,801     $ 73,499     $ 73,013     $ 63,887  
Cash Dividends on Common Stock (in thousands)
  $ 62,000     $ 66,200     $ 66,000     $ 63,500     $ 50,200  
Return on Average Common Equity (percent)
    13.33       14.24       13.99       14.46       14.25  
Total Assets (in thousands)
  $ 1,981,269     $ 1,479,113     $ 1,511,174     $ 1,482,040     $ 1,411,050  
Gross Property Additions (in thousands)
  $ 158,084     $ 70,063     $ 69,345     $ 67,460     $ 61,193  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 561,160     $ 545,837     $ 532,489     $ 517,953     $ 491,680  
Preferred stock
    32,780       32,780       31,809       31,809       31,809  
Mandatorily redeemable preferred securities
                35,000       35,000       35,000  
Long-term debt payable to affiliated trust
    36,082       36,082                    
Long-term debt
    242,548       242,498       202,488       243,715       233,753  
 
Total (excluding amounts due within one year)
  $ 872,570     $ 857,197     $ 801,786     $ 828,477     $ 792,242  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    64.3       63.7       66.4       62.5       62.1  
Preferred stock
    3.8       3.8       4.0       3.8       4.0  
Mandatorily redeemable preferred securities
                4.4       4.2       4.4  
Long-term debt payable to affiliated trust
    4.1       4.2                    
Long-term debt
    27.8       28.3       25.2       29.5       29.5  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Security Ratings:
                                       
First Mortgage Bonds —
                                       
Moody’s
                  Aa3             Aa3             Aa3             Aa3
Standard and Poor’s
          A+       A+       A+       A+  
Fitch
                  AA             AA-             AA-             AA-
Preferred Stock —
                                       
Moody’s
    A3       A3       A3       A3       A3  
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       A1  
Standard and Poor’s
    A       A       A       A       A  
Fitch
            AA-            AA-     A+       A+       A+  
 
Customers (year-end) :
                                       
Residential
    142,077       160,189       159,582       158,873       158,852  
Commercial
    30,895       33,646       33,135       32,713       32,538  
Industrial
    512       522       520       489       498  
Other
    176       183       171       171       173  
 
Total
    173,660       194,540       193,408       192,246       192,061  
 
Employees (year-end)
    1,254       1,283       1,290       1,301       1,316  
 

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Mississippi Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands) :
                                       
Residential
  $ 209,546     $ 199,242     $ 180,978     $ 186,522     $ 164,716  
Commercial
    213,093       199,127       175,416       181,224       163,253  
Industrial
    190,720       180,516       154,825       164,042       156,525  
Other
    5,501       5,428       5,082       5,039       4,659  
 
Total retail
    618,860       584,313       516,301       536,827       489,153  
Sales for resale — non-affiliates
    283,413       265,863       249,986       224,275       204,623  
Sales for resale — affiliates
    50,460       44,371       26,723       46,314       85,652  
 
Total revenues from sales of electricity
    952,733       894,547       793,010       807,416       779,428  
Other revenues
    17,000       15,779       76,914       16,749       16,637  
 
Total
  $ 969,733     $ 910,326     $ 869,924     $ 824,165     $ 796,065  
 
Kilowatt-Hour Sales (in thousands) :
                                       
Residential
    2,179,756       2,297,110       2,255,445       2,300,017       2,162,623  
Commercial
    2,725,274       2,969,829       2,914,133       2,902,291       2,840,840  
Industrial
    3,798,477       4,235,290       4,111,199       4,161,902       4,275,781  
Other
    37,905       40,229       39,890       39,635       41,009  
 
Total retail
    8,741,412       9,542,458       9,320,667       9,403,845       9,320,253  
Sales for resale — non-affiliates
    4,811,250       6,027,666       5,874,724       5,380,145       5,011,212  
Sales for resale — affiliates
    896,361       1,053,471       709,065       1,586,968       2,952,455  
 
Total
    14,449,023       16,623,595       15,904,456       16,370,958       17,283,920  
 
Average Revenue Per Kilowatt-Hour (cents) :
                                       
Residential
    9.61       8.67       8.02       8.11       7.62  
Commercial
    7.82       6.70       6.02       6.24       5.75  
Industrial
    5.02       4.26       3.77       3.94       3.66  
Total retail
    7.08       6.12       5.54       5.71       5.25  
Sales for resale
    5.85       4.38       4.20       3.88       3.64  
Total sales
    6.59       5.38       4.99       4.93       4.51  
Residential Average Annual Kilowatt-Hour Use Per Customer
    14,111       14,357       14,161       14,453       13,634  
Residential Average Annual Revenue Per Customer
  $ 1,367     $ 1,245     $ 1,136     $ 1,172     $ 1,038  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    3,156       3,156       3,156       3,156       3,156  
Maximum Peak-Hour Demand (megawatts) :
                                       
Winter
    2,178       2,173       2,458       2,311       2,249  
Summer
    2,493       2,427       2,330       2,492       2,466  
Annual Load Factor (percent)
    56.6       62.4       60.5       61.8       60.7  
Plant Availability Fossil-Steam (percent) :
    82.8       91.4       92.6       91.7       92.8  
 
Source of Energy Supply (percent) :
                                       
Coal
    58.1       55.7       57.7       50.8       52.0  
Oil and gas
    24.4       25.5       19.9       37.7       35.9  
Purchased power —
                                       
From non-affiliates
    5.1       6.4       3.5       3.1       3.1  
From affiliates
    12.4       12.4       18.9       8.4       9.0  
 
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 (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, 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, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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-306 to II-329) present fairly, in all material respects, the financial position of Savannah Electric and Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
     As discussed in Note 3 to the financial statements, on December 13, 2005, the Company’s Board approved the merger with Georgia Power Company, subject to regulatory approval.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Savannah Electric and Power Company 2005 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 the Company’s business of selling electricity. These factors include the Company’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and rising fuel prices. In 2005, the Company completed a retail base rate case and a retail fuel cost recovery rate case. These regulatory actions are expected to benefit future earnings stability, 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. In connection with the merger, as discussed below, additional rate actions are expected to be completed in 2006.
Merger with Georgia Power
On December 13, 2005, the Company entered into a merger agreement with Georgia Power Company (Georgia Power) under which the Company will merge into Georgia Power, with Georgia Power continuing as the surviving corporation (the Merger). The Merger must be approved by Savannah Electric’s preferred shareholders and is subject to the receipt of regulatory approval of the Federal Energy Regulatory Commission (FERC), the Georgia Public Service Commission (PSC), and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to occur by July 2006. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Merger” herein and Note 3 under “Retail Regulatory Matters — Merger” for additional information.
Key Performance Indicators
In striving to maximize shareholder value while providing cost effective energy to more than 147,000 customers, the Company focuses on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. 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 customer satisfaction surveys and reliability indicators to evaluate the Company’s results.
     Peak season equivalent forced outage rate (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. Peak Season EFOR excludes the impact of hurricanes and certain outage events caused by manufacturer defects. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, normal weather conditions, and expected capital expenditures. The 2005 performance was on target on these reliability measures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.
     The Company’s 2005 results compared to its targets for some of its key indicators are reflected in the following chart.
         
Key   2005   2005
Performance Indicator   Target Performance   Actual Performance
Customer Satisfaction   Top quartile in customer surveys   Second quartile
Peak Season EFOR   3.0% or less   1.0%
Net Income   $25.2 million   $29.9 million
     The failure to achieve top quartile in customer satisfaction is believed to have been the result of three rate increases since November 2004, which was a significant consideration in the Merger decision. The financial performance and Peak Season EFOR achieved in 2005 reflect the focus management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report
Earnings
The Company’s net income after preferred stock dividends for 2005 totaled $29.9 million, representing an increase of $5.7 million, or 23.5 percent, from the prior year. Higher operating revenues resulting from the base rate increase in June 2005, as well as increases in transmission revenues and other income were somewhat offset by higher operating expenses and higher interest expense resulting from additional securities outstanding and higher interest rates. Earnings were $24.2 million in 2004, reflecting an increase of $0.8 million, or 3.3 percent, from the prior year. Higher operating revenues from customer growth were somewhat offset by higher operating expenses and higher interest expenses resulting from additional securities outstanding. In 2003, earnings were $23.5 million, representing 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.
RESULTS OF OPERATIONS
A condensed income statement is as follows:
                                 
            Increase (Decrease)  
    Amount     from Prior Year  
 
    2005     2005     2004     2003  
 
            (in thousands)          
Operating revenues
  $ 444,994     $ 88,034     $ 41,843     $ 18,111  
 
Fuel
    106,549       50,553       119       922  
Purchased power
    146,247       20,573       36,169       13,901  
Other operation and maintenance
    93,014       7,049       2,344       2,603  
Depreciation and amortization
    22,404       1,152       753       (2,205 )
Taxes other than income taxes
    16,202       957       580       208  
 
Total operating expenses
    384,416       80,284       39,965       15,429  
 
Operating income
    60,578       7,750       1,878       2,682  
Total other income and (expense)
    (10,956 )     1,762       (745 )     3,528  
Income taxes
    16,989       2,611       (1,140 )     4,070  
 
Net income
    32,633       6,901       2,273       2,140  
Dividends on preferred stock
    2,700       1,200       1,500        
 
Net income after dividends on preferred stock
  $ 29,933     $ 5,701     $ 773     $ 2,140  
 
Revenues
Details of operating revenues are as follows:
                         
    Amount  
 
    2005     2004     2003  
 
        (in thousands)      
Retail — prior year
  $ 341,766     $ 298,807     $ 283,225  
Change in —
                       
Base rates
    6,097             2,799  
Sales growth
    1,696       9,497       2,084  
Weather
    1,127       10       (263 )
Fuel cost recovery and other
    70,865       33,452       10,962  
 
Retail — current year
    421,551       341,766       298,807  
 
Sales for resale —
                       
Non-affiliates
    5,126       5,035       5,653  
Affiliates
    10,536       6,130       6,499  
 
Total sales for resale
    15,662       11,165       12,152  
 
Other operating revenues
    7,781       4,029       4,158  
 
Total operating revenues
  $ 444,994     $ 356,960     $ 315,117  
 
Percent change
    24.7 %     13.3 %     6.1 %
 
     Total operating revenues for 2005 were $445.0 million, reflecting a 24.7 percent increase when compared to 2004. Retail revenues increased 23.3 percent, or $79.8 million, in 2005, increased 14.4 percent, or $43.0 million, in 2004, and increased 5.5 percent, or $15.6 million, in 2003. On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for the Company ending May 31, 2008 (2005 Retail Rate Plan). Retail base rates also increased in June 2002. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.
     Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under the fuel recovery provisions, fuel revenues generally equal fuel expenses—including the fuel component of purchased energy—and do not affect net income. The Georgia PSC approved a Fuel Cost Recovery (FCR) rate increase that became effective in December 2005. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein and Notes 1 and 3 to the financial statements under “Fuel Costs” and “Retail Regulatory Matters —Fuel Cost Recovery,” respectively, for additional information.
     Revenues from sales to non-affiliated utilities are primarily energy related. These sales do not have a

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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 Intercompany Interchange Contract (IIC), as approved by the 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 2005 and the percent change by year were as follows:
                                 
    KWH     Percent Change
 
                               
    2005     2005     2004     2003  
 
                               
    (in millions)                          
Residential
    1,923       1.3 %     8.3 %     (0.1 )%
Commercial
    1,566       1.7       5.4       0.4  
Industrial
    805       (4.2 )     (2.4 )     8.8  
Other
    136       (4.7 )     4.1       (0.5 )
 
                             
Total retail
    4,430       0.2       5.0       1.8  
Sales for resale —
                               
Non-affiliates
    84       (36.1 )     (19.2 )     7.7  
Affiliates
    178       24.8       (22.9 )     47.1  
 
                             
Total
    4,692       (0.1 )%     3.0 %     3.3 %
 
     In 2005, residential and commercial energy sales increased from the prior year primarily due to continued customer growth and favorable weather conditions. Industrial sales were lower as compared to the prior year due to lower usage by several industrial customers resulting from cogeneration, plant outages, and reductions in production.
     In 2004, residential and commercial energy sales increased from the prior year primarily due to continued customer growth. Industrial sales were lower than the prior year because of lower usage by several industrial customers due to cogeneration and cutbacks in production.
     In 2003, residential sales decreased from the prior year primarily due to weather-related demand. Industrial sales were higher than the prior year 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.
     Energy sales to retail customers are projected to increase at a compound average growth rate of 2.4 percent during the period 2006 through 2010.
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:
                         
    2005     2004     2003  
     
Total generation (millions of KWHs)
    2,569       2,135       2,325  
Sources of generation (percent) —
                       
Coal
    79       96       94  
Oil
    1       1       2  
Gas
    20       3       4  
Average cost of fuel per net KWH generated (cents)
    4.15       2.62       2.40  
Total purchased power (millions of KWHs)
    2,472       2,829       2,581  
Average cost of purchased power per net KWH (cents)
    5.92       4.44       3.47  
 
     Fuel expense increased 90.3 percent in 2005 as compared to 2004 due to a 58.4 percent increase in the average cost of fuel per net KWH generated and a 20.3 percent increase in generation due to the commercial operation of the Plant McIntosh Combined Cycle Units 10 and 11 in June 2005. In 2004, fuel expense increased 0.2 percent over the prior year due to a 9.2 percent increase in the average cost of fuel per net KWH generated that more than offset an 8.2 percent decrease in generation. In 2003, fuel expense increased 1.7 percent as compared to the prior year due to a slight increase in generation offset somewhat by a lower cost of coal.
     Purchased power expense increased $20.6 million, or

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16.4 percent, in 2005 as compared to 2004 resulting from the increases in fuel costs which drove higher energy costs. In 2004, purchased power expense increased $36.2 million, or 40.4 percent over the prior year due to increased energy demands and higher energy costs. In 2003, purchased power expense increased $13.9 million, or 18.4 percent, over the prior year 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.
     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 increased mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term 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 $7.0 million, or 8.2 percent, in 2005 over the prior year primarily due to increases of $4.0 million in production expenses related to scheduled maintenance outages at both Plant Kraft and Plant McIntosh, $1.4 million in transmission expenses related in part to a transformer failure and new transmission facilities agreements, $0.6 million in distribution expenses related to tree trimming, and increases of $0.5 million in administrative and general expenses primarily related to employee benefits expenses and Sarbanes-Oxley related accounting activities, offset partially by a decrease of $0.7 million in the storm damage accrual as ordered in the 2005 Retail Rate Plan.
     In 2004, other operation and maintenance expenses increased $2.3 million, or 2.8 percent over the prior year, 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 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, over the prior year. 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.
     Depreciation and amortization increased $1.2 million, or 5.4 percent, in 2005 over the prior year due to the completion of the amortization of the regulatory liability for accelerated depreciation in May 2005 in accordance with the 2002 Georgia PSC rate order and the addition of the McIntosh combined cycle facilities in June 2005 partially offset by lowering the composite depreciation rate as part of the 2005 Retail Rate Plan. In 2004, depreciation and amortization increased $0.8 million, or 3.7 percent, from the prior year due to an increase in depreciable property. Depreciation and amortization decreased $2.2 million, or 9.7 percent, in 2003 from the prior year primarily as a result of discontinuing accelerated depreciation and beginning amortization of the related regulatory liability in June 2002. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.
Other Income (Expense), Net
Other income increased in 2005 over the prior year as a result of a $2.6 million gain on the settlement of gas hedges, as allowed by the Georgia PSC, and a $2.5 million disallowance of Plant McIntosh construction costs recorded in December 2004. These increases were partially offset by $0.9 million in expenses associated with the Company’s non-qualified benefit plans in connection with the Merger. In 2004, other income decreased over the prior year due to the Plant McIntosh disallowance. Other income increased in 2003 over the prior year as a result of a distribution of the proceeds

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from the sale of a mutual life insurance company in which the Company held policies used to fund its non-qualified benefit plans. See Notes 2 and 3 to the financial statements under “Retail Regulatory Matters — Fuel Hedging Program” and — “Plant McIntosh Construction Project” for additional information.
Non-Operating Expenses
In 2005, interest expense and preferred dividends increased $3.9 million, or 29.0 percent, over the prior year due to the issuance of senior notes and preferred stock in 2004, as well as an increase in short-term borrowings and higher interest rates. Interest expense and preferred dividends increased $4.0 million, or 41.3 percent, in 2004 over the prior year primarily related to an increase in senior notes and preferred stock outstanding. These increases were partially offset by a decrease in distributions on mandatorily redeemable preferred securities due to the redemption of $40 million of mandatorily redeemable preferred securities. Interest expense decreased $2.0 million, or 17.4 percent, in 2003 from the prior year primarily as a result of a lower principal amount of debt outstanding during the year. Lower interest rates also contributed to lower expenses in 2003. 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 stock. 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 may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” and “FERC Matters” 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 Company’s ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.
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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added the Company as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District

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Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plant Kraft. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and the Company has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions” for additional information.
     The Company believes 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. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.
Carbon Dioxide Litigation
In July 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. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.
Environmental Statutes and Regulations
General
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. Applicable statutes include the Clean Air Act; Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Resource

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Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. 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. Through 2005, the Company had invested approximately $10.8 million in capital projects to comply with these requirements, with annual totals of $1.5 million, $3.4 million, and $0.7 million for 2003, 2004, and 2005, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $31.2 million, including $0.6 million and $4.5 million for 2006 and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. 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.
     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $2.8 million in reducing nitrogen oxide (NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional measures are under consideration to further reduce SO2 and NOx emissions, to maintain compliance with existing regulations and to meet new requirements.
     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. During 2005, the EPA’s fine particulate matter nonattainment designations also became effective for several areas across the United States. No areas within the Company’s service area, however, have been designated as nonattainment under either the eight-hour ozone standard or the fine particulate matter standard. Although the State of Georgia was originally included in the states subject to the regional NOx rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NOx reduction rules for the State of Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of its state implementation plan.
     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO2 and NOx emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NOx and/or SO2 to be achieved in two phases, 2009/2010 and 2015. These reductions may be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.
     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO2 and NOx. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and

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reasonable progress toward the goal.
     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.
     The impacts of the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO2, NOx, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.
Water Quality
In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies and therefore, cannot now be determined.
Environmental Remediation
The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release 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 the 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.
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; however, in 2002, it did announce 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 involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 — 2012. Southern Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

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FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. Through Southern Company Services, Inc. (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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and the Company be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is to vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

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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.
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 “Market-Based Rate Authority” and “Generation Interconnection Agreements” above 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.
PSC Matters
Merger
In connection with the Merger, Georgia Power and the Company plan to establish a new coastal regional organization for Georgia Power that will operate following completion of the Merger. Management expects that current employees of the Company will fill most of the positions in the new regional organization. In connection with the Merger, the Company plans to offer voluntary severance to a number of employees and expects to incur approximately $16 million in expenses related to severance benefits and termination costs associated with the Company’s Supplemental Executive Retirement Plan. These anticipated severance benefits will result in cash payments that are expected to be expensed during the first half of 2006. The actual amount and timing of these charges may differ materially from the Company’s estimates described above and will depend upon the final composition and seniority of the affected employees and the actual timing of completion of the Merger and the development of the coastal regional organization of Georgia Power.
     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, Georgia Power and the Company filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, Georgia Power and the Company are seeking the approval of the Georgia PSC with respect to the following matters:
  the transfer of the Company’s generating facilities and certification of the generating facilities as Georgia Power assets;
  amendments to Georgia Power’s Integrated Resource Plan to add the current customers and generating facilities of the Company;
  the transfer of the Company’s assigned service territory to Georgia Power;
  adoption of Georgia Power’s service rules and regulations to the current Savannah Electric customers;
  new fuel rate and base rate schedules that would apply to Georgia Power’s sale of electricity to the current company customers; and
  the issuance of additional shares of Georgia Power common stock to Southern Company in exchange for Southern Company’s shares of the Company’s common stock.
     Georgia Power has also requested that the Georgia PSC better align the rates for the Company’s customers with those of Georgia Power. Currently, customers of the Company pay slightly lower base rates and significantly higher fuel rates than Georgia Power customers. The overall effect is that customers of the Company pay substantially higher overall costs for electricity. See “Rate Filing” and “Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

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Rate Filing
In November 2004, the Company filed a rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in total retail revenues, effective January 1, 2005 to cover the cost of new generation and PPAs, higher operating and maintenance expenses, and continued investment in new transmission and distribution facilities to support growth and ensure reliability. The requested increase was based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent.
     On May 17, 2005, the Georgia PSC approved the 2005 Retail Rate Plan. Under the terms of the 2005 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 9.75 percent to 11.75 percent. Two-thirds of any earnings above 11.75 percent will be applied to rate refunds with the remaining one-third retained by the Company. Retail base revenues increased in June 2005 by approximately $9.6 million, or 5.1 percent, on an annual basis. If the Merger is not completed, the Company would be required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued. In connection with the Merger, Georgia Power has requested Georgia PSC approval of a “merger transition charge” that would be used to adjust the Company’s total base revenues to more closely match the existing base rates for Georgia Power. The merger transition charge would remain in effect until completion of Georgia Power’s next base rate case in 2007 that would be effective on January 1, 2008. See Note 3 to the financial statements under “Retail Regulatory Matters — Merger” for additional information.
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, which were then under construction. 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 construction 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. See “FERC Matters — Intercompany Interchange Contract” above for additional information.
     In December 2004, the Georgia PSC approved the transfer of the Plant McIntosh construction project, at a total fair market value of approximately $385 million. This value reflected an approximate $16 million disallowance of which approximately $3 million is attributable to the Company and reduced the Company’s 2004 net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Combined Cycle Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. In connection with the Company’s 2005 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates.
Fuel Cost Recovery
On November 10, 2005, the Georgia PSC voted to approve the Company’s request to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs. Fuel revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the customer fuel rates will have no significant effect on the Company’s net income, but is

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expected to increase annual cash flow by approximately $52.4 million.
     As a result of recent increases in fuel costs, the Georgia PSC ordered the Company to file a new fuel case on or before January 17, 2006. In connection with the Merger, the Company requested and the Georgia PSC agreed to postpone the January 2006 filing. Instead, the Company and Georgia Power plan to jointly file a fuel case in March 2006 that would seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined generating fleet. The new fuel cost recovery rate would be paid by all Georgia Power customers following the Merger, including the existing customers of the Company. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups. See “Merger” herein for additional information.
     In a separate proceeding on August 2, 2005, the Georgia PSC initiated an investigation of the Company’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. The Company and Georgia Power are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.
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 $6.2 million, $5.3 million, and $4.3 million 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were approximately $3.0 million in 2005, $2.8 million in 2004, and $2.7 million in 2003. Both pension and postretirement costs are expected to continue to trend upward. Future costs are dependent on several factors including trust earnings and changes to the plans. A portion of pension 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.
     Effective September 30, 2004, the Company retired Units 4 and 5 at Plant Riverside. The remaining units at the plant were retired on May 31, 2005. These retirements had 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. Management has reviewed and discussed critical accounting policies and estimates 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 (Statement No. 71), 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

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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 and accounting principles generally accepted in the United States. 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, 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
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of their retirements was dependent on future events. At

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December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $3.3 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”
Stock Options
On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company’s financial condition continued to be stable at December 31, 2005. As of December 31, 2005, the Company’s capital structure consisted of 47.7 percent common stockholder’s equity, 8.8 percent preferred stock, and 43.5 percent long-term debt, excluding amounts due within one year.
     The principal change in the Company’s financial condition in 2005 was the addition of $52.3 million to utility plant, the majority of which was related to completion of Plant McIntosh Units 10 and 11. 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. See statements of cash flows 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 from sources similar to those used in the past, including funds from operations and capital contributions from Southern Company. 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, type, and timing of any future financings — if needed — will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors.
     The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term securities by the Company is generally subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (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 2006, the Company had $80 million of unused short-term and revolving credit arrangements with banks to meet its short-term cash needs. Of this amount, $60 million will expire at various times in 2006 and $20 million will expire in 2008. The arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted to the indebtedness of the Company. The Company is currently in compliance with all such covenants. 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 retail operating companies.

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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, 2005, the Company had outstanding $49.9 million in commercial paper and $8.9 million in extendible commercial notes.
     The Company’s committed credit arrangements provide liquidity support to some of the Company’s variable rate obligations and to its commercial paper program. At December 31, 2005, the amount of variable rate obligations outstanding requiring liquidity support was $6.7 million.
     The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.
Financing Activities
Maturities and redemptions of long-term debt and mandatorily redeemable preferred securities were $1.1 million in 2005, $71.0 million in 2004, and $39.8 million in 2003. The Company issued no new securities in 2005.
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, 2005, 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 future exposure to change in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as cash flow hedges. The weighted average rate on $6.7 million of variable rate long-term debt outstanding that has not been hedged at January 1, 2006 was 4.04 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, at January 1, 2006, the change would not materially affect annualized interest expense. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.
     To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. In addition, the Company has implemented a natural gas/oil hedging program ordered by the Georgia PSC. The program limits the recovery of losses on financial hedging positions through the fuel clause to 10 percent of the Company’s annual natural gas/oil budget. These hedging position limits were $1.1 million for 2003, $2.7 million for 2004, and $5.1 million for 2005 and will be $7.4 million for 2006. The program has operated within the defined hedging position limits set for each year. See Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Hedging Program” for additional information.

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     The changes in fair value of energy related derivative contracts and year-end valuations were as follows at December 31:
                 
    Changes in Fair Value
    2005     2004
    (in thousands)  
Contracts beginning of year
  $ 1,474     $ 463  
Contracts realized or settled
    (6,895 )     (1,811 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    14,169       2,822  
 
Contracts end of year
  $ 8,748     $ 1,474  
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
Source of 2005 Year-End Valuation Prices
    Total     Maturity
    Fair Value     Year 1     2-3 Years
    (in thousands)  
 
Actively quoted
  $ 8,762     $ 6,394     $ 2,368  
External sources
    (14 )     (14 )      
Models and other methods
                 
 
Contracts end of year
  $ 8,748     $ 6,380     $ 2,368  
 
     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, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts  
    (in thousands)
Regulatory liabilities, net
  $ 8,752  
Other comprehensive income
     
Net income
    (4 )
 
Total fair value
  $ 8,748  
 
     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 $44.7 million in 2006, $33.5 million in 2007, and $55.8 million in 2008. Environmental expenditures included in these amounts are $0.6 million in 2006 and $4.4 million for 2008. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Construction of new transmission and distribution facilities and capital improvements for generation, transmission, and distribution facilities, including those needed to meet the environmental standards previously discussed, will be ongoing.
     As discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC.
     Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, 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
                                         
            2007-     2009-     After        
    2006     2008     2010     2010     Total  
    (in thousands)  
Long-term debt(a)
                                       
Principal
  $ 21,003     $ 47,020     $ 1,366     $ 168,647     $ 238,036  
Interest
    13,294       23,677       17,585       139,187       193,743  
Commodity derivative obligations(b)
    901       2                   903  
Preferred stock dividends(c)
    2,700       5,400       5,400             13,500  
Operating leases
    909       1,573       1,077       3,179       6,738  
Purchase commitments(d)
                                       
Capital(e)
    44,696       89,261                   133,957  
Coal
    60,615       11,073                   71,688  
Natural gas(f)
    60,829       51,288       87,886       362,804       562,807  
Purchased power
    13,240       26,531       13,286             53,057  
Long-term service agreements
    1,212       3,146       4,280       27,223       35,861  
Postretirement benefit trusts(g)
    1,300       2,600                   3,900  
 
Total
  $ 220,699     $ 261,571     $ 130,880     $ 701,040     $ 1,314,190  
 
 
(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, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
 
(b)   For additional information, see Notes 1 and 6 to the financial statements herein.
 
(c)   Preferred stock does not mature; therefore, amounts are provided for the next five years only. In connection with the Merger, the Company’s preferred stock is expected to be exchanged for Georgia Power preferred stock.
 
(d)   The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $93.0 million, $86.0 million, and $83.6 million, respectively.
 
(e)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
 
(f)   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, 2005.
 
(g)   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 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, earnings growth, completion of construction projects, estimated construction and other expenditures, financing activities, access to sources of capital, the merger of the Company and Georgia Power, impacts of the adoption of new accounting rules, 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, implementation of the Energy Policy Act of 2005, 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 and FERC matters;
 
  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, including rate cases relating to fuel cost recovery;
 
  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 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 by the Company from time to time with the Securities and Exchange Commission.
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, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report
                         
    2005     2004     2003  
 
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 421,551     $ 341,766     $ 298,807  
Sales for resale —
                       
Non-affiliates
    5,126       5,035       5,653  
Affiliates
    10,536       6,130       6,499  
Other revenues
    7,781       4,029       4,158  
 
Total operating revenues
    444,994       356,960       315,117  
 
Operating Expenses:
                       
Fuel
    106,549       55,996       55,877  
Purchased power —
                       
Non-affiliates
    12,470       11,413       5,713  
Affiliates
    133,777       114,261       83,792  
Other operations
    62,718       61,134       56,823  
Maintenance
    30,296       24,831       26,798  
Depreciation and amortization
    22,404       21,252       20,499  
Taxes other than income taxes
    16,202       15,245       14,665  
 
Total operating expenses
    384,416       304,132       264,167  
 
Operating Income
    60,578       52,828       50,950  
Other Income and (Expense):
                       
Interest income
    255       208       290  
Interest expense, net of amounts capitalized
    (14,778 )     (12,047 )     (9,590 )
Distributions on mandatorily redeemable preferred securities
          (109 )     (2,740 )
Other income (expense), net
    3,567       (770 )     67  
 
Total other income and (expense)
    (10,956 )     (12,718 )     (11,973 )
 
Earnings Before Income Taxes
    49,622       40,110       38,977  
Income taxes
    16,989       14,378       15,518  
 
Net Income
    32,633       25,732       23,459  
Dividends on Preferred Stock
    2,700       1,500        
 
Net Income After Dividends on Preferred Stock
  $ 29,933     $ 24,232     $ 23,459  
 
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, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report
                         
    2005     2004     2003  
 
    (in thousands)  
Operating Activities:
                       
Net income
  $ 32,633     $ 25,732     $ 23,459  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    24,698       23,710       22,587  
Deferred income taxes and investment tax credits, net
    25,792       13,441       654  
Allowance for equity funds used during construction
    (2,337 )     (2,379 )     (193 )
Pension, postretirement, and other employee benefits
    6,133       4,866       5,312  
Tax benefit of stock options
    1,552       861       884  
Other, net
    2,871       (7,758 )     4,261  
Changes in certain current assets and liabilities —
                       
Receivables
    (62,593 )     (26,432 )     212  
Fossil fuel stock
    (5,426 )     (1,938 )     (323 )
Materials and supplies
    (1,863 )     (842 )     516  
Other current assets
    175       (5,324 )     4,615  
Accounts payable
    15,497       5,035       3,713  
Accrued taxes
    (3,628 )     3,352       (1,131 )
Accrued compensation
    340       (40 )     (819 )
Other current liabilities
    (174 )     (911 )     (4,492 )
 
Net cash provided from operating activities
    33,670       31,373       59,255  
 
Investing Activities:
                       
Property additions
    (48,443 )     (47,677 )     (39,015 )
Purchase of property from affiliates
          (74,832 )      
Other
    (1,656 )     539       974  
 
Net cash used for investing activities
    (50,099 )     (121,970 )     (38,041 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    38,203       20,567       (2,897 )
Proceeds —
                       
Pollution control bonds
                13,870  
Senior notes
          35,000       60,000  
Other long-term debt
          10,000        
Preferred stock
          45,000        
Capital contributions from parent company
    442       47,255       6,757  
Redemptions —
                       
Pollution control bonds
                (13,870 )
Senior notes
                (20,000 )
Other long-term debt
    (1,095 )     (31,014 )     (5,944 )
Mandatorily redeemable preferred securities
          (40,000 )      
Payment of preferred stock dividends
    (2,700 )     (825 )      
Payment of common stock dividends
    (26,700 )     (23,200 )     (23,000 )
Other
    (81 )     (1,267 )     (2,165 )
 
Net cash provided from financing activities
    8,069       61,516       12,751  
 
Net Change in Cash and Cash Equivalents
    (8,360 )     (29,081 )     33,965  
Cash and Cash Equivalents at Beginning of Year
    8,862       37,943       3,978  
 
Cash and Cash Equivalents at End of Year
  $ 502     $ 8,862     $ 37,943  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $1,079, $1,471, and $220 capitalized, respectively)
  $ 13,358     $ 10,080     $ 11,334  
Income taxes (net of refunds)
    (11,042 )     4,581       8,439  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Savannah Electric and Power Company 2005 Annual Report
                 
Assets   2005     2004  
 
      (in thousands)
Current Assets:
               
Cash and cash equivalents
  $ 502     $ 8,862  
Receivables —
               
Customer accounts receivable
    29,116       22,875  
Unbilled revenues
    6,651       6,681  
Under recovered regulatory clause revenues
    28,990       23,800  
Other accounts and notes receivable
    2,055       1,608  
Affiliated companies
    5,449       3,392  
Accumulated provision for uncollectible accounts
    (916 )     (878 )
Fossil fuel stock, at average cost
    16,015       10,590  
Materials and supplies, at average cost
    11,776       9,913  
Prepaid income taxes
    22,629       21,615  
Assets from risk management activities
    8,045       1,772  
Other
    2,824       1,930  
 
Total current assets
    133,136       112,160  
 
Property, Plant, and Equipment:
               
In service
    1,033,256       945,359  
Less accumulated provision for depreciation
    396,987       408,415  
 
 
    636,269       536,944  
Construction work in progress
    21,315       91,275  
 
Total property, plant, and equipment
    657,584       628,219  
 
Other Property and Investments
    4,279       3,925  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    11,455       10,588  
Cash surrender value of life insurance for deferred compensation plans
    27,030       25,335  
Deferred under recovered regulatory clause revenues
    48,689        
Other regulatory assets
    20,191       23,527  
Other
    10,437       8,837  
 
Total deferred charges and other assets
    117,802       68,287  
 
Total Assets
  $ 912,801     $ 812,591  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2005 and 2004
Savannah Electric and Power Company 2005 Annual Report
                 
Liabilities and Stockholder’s Equity   2005     2004  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 21,003     $ 1,010  
Notes payable
    58,771       20,567  
Accounts payable —
               
Affiliated
    29,840       17,379  
Other
    19,355       16,166  
Customer deposits
    7,068       6,973  
Accrued taxes —
               
Income taxes
          148  
Other
    1,909       5,390  
Accrued interest
    3,223       3,050  
Accrued compensation
    5,952       5,612  
Other
    15,020       9,426  
 
Total current liabilities
    162,141       85,721  
 
Long-term Debt (See accompanying statements)
    217,033       237,769  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    119,424       90,079  
Deferred credits related to income taxes
    7,978       8,738  
Accumulated deferred investment tax credits
    7,298       7,961  
Employee benefit obligations
    54,661       46,580  
Other cost of removal obligations
    40,575       41,890  
Other regulatory liabilities
    12,107       11,066  
Other
    10,127       6,693  
 
Total deferred credits and other liabilities
    252,170       213,007  
 
Total Liabilities
    631,344       536,497  
 
Preferred Stock (See accompanying statements)
    43,909       43,938  
 
Common Stockholder’s Equity (See accompanying statements)
    237,548       232,156  
 
Total Liabilities and Stockholder’s Equity
  $ 912,801     $ 812,591  
 
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, 2005 and 2004
Savannah Electric and Power Company 2005 Annual Report
                                 
    2005     2004     2005     2004  
    (in thousands)     (percent of total)  
Long-Term Debt:
                               
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       150,000                  
 
Total long-term notes payable
    195,000       195,000                  
 
Other long-term debt —
                               
Non-collateralized pollution control revenue bonds —
                               
Variable rates (2.65% to 3.75% at 1/1/06)
                               
due 2016-2038
    17,955       17,955                  
 
Capitalized lease obligations
    5,081       5,824                  
 
Total long-term debt (annual interest requirement — $13.3 million)
    238,036       238,779                  
Less amount due within one year
    21,003       1,010                  
 
Long-term debt excluding amount due within one year
    217,033       237,769       43.5 %     46.2 %
 
Non-Cumulative Preferred Stock:
                               
$25 par value — 6.00%
                               
Authorized — 4,000,000 shares
                               
Outstanding — 1,800,000 shares
                               
(annual dividend requirement — $2.7 million)
    43,909       43,938       8.8       8.6  
 
Common Stockholder’s Equity:
                               
Common stock, par value $5 per share —
                               
Authorized - 16,000,000 shares
                               
Outstanding - 10,844,635 shares
    54,223       54,223                  
Paid-in capital
    74,527       72,533                  
Retained earnings
    110,939       107,685                  
Accumulated other comprehensive income (loss)
    (2,141 )     (2,285 )                
 
Total common stockholder’s equity
    237,548       232,156       47.7 %     45.2 %
 
Total Capitalization
  $ 498,490     $ 513,863       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, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report
                                         
                            Other    
    Common   Paid-In   Retained   Comprehensive    
    Stock   Capital   Earnings   Income (loss)   Total
                  (in thousands)                  
Balance at December 31, 2002
  $ 54,223     $ 16,776     $ 106,194     $ (1,244 )   $ 175,949  
Net income
                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
    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  
Net income after dividends on preferred stock
                29,933             29,933  
Capital contributions from parent company
          1,994                   1,994  
Other comprehensive income (loss)
                      144       144  
Cash dividends on common stock
                (26,700 )           (26,700 )
Other
                21             21  
 
Balance at December 31, 2005
  $ 54,223     $ 74,527     $ 110,939     $ (2,141 )   $ 237,548  
 
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)                   
Net income after dividends on preferred stock
  $ 29,933     $ 24,232     $ 23,459  
 
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(235), $(253) and $(336), respectively
    (371 )     (401 )     (533 )
Changes in fair value of qualifying hedges, net of tax of $308, $161 and $(284), respectively
    494       255       (450 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $13, $41 and $15, respectively
    21       65       23  
 
Total other comprehensive income (loss)
    144       (81 )     (960 )
 
Comprehensive Income
  $ 30,077     $ 24,151     $ 22,499  
 
 
The accompanying notes are an integral part of these financial statements.
                       

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NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2005 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 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). 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 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. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
     Certain prior years’ data presented in the financial statements has been reclassified to conform with the current year presentation.
     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were 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.
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 services with respect to business and operations and power pool transactions. Costs for these services amounted to $17.9 million, $17.4 million, and $16.3 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA and management believes they are reasonable.
     The Company has 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 2005 amounted to $50.7 million. At December 31, 2005, approximately $0.9 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 $1.9 million in 2005, $3.3 million in 2004, and $3.6 million in 2003.
     In addition, the Company and Georgia Power jointly

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report
acquired, in 2004, the Plant McIntosh Combined Cycle Units 10 and 11 construction project from Southern Power. The Company also operates these units which were placed in service in June 2005. Georgia Power reimburses the Company for its proportionate share of the related expenses, which were $3.6 million for 2005. See Note 3 under “Retail Regulatory Matters — Plant McIntosh Construction Project” and Notes 4 and 5 for additional information.
     The Company provides incidental services to other subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in the last two years, assistance provided to aid in storm restoration has caused an increase in these activities. The total amount of storm restoration provided in 2004 and 2005 was $0.5 million and $1.2 million, respectively. These activities were billed at cost.
     The retail operating companies, including the Company, and Southern Power 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.
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 and the amortization periods are discussed below as follows:
                         
    2005     2004     Note  
    (in thousands)          
Asset retirement obligations
  $ 5,610     $ 3,868       (a )
Deferred income tax charges
    11,455       10,588       (a )
Loss on reacquired debt
    7,209       7,935       (b )
Deferred McIntosh maintenance costs
    7,370       8,599       (c )
Coal transloader
          3,077       (d )
Fuel-hedging assets
    889       563       (f )
Other cost of removal obligations
    (40,575 )     (41,890 )     (a )
Fuel-hedging liabilities
    (9,642 )     (2,034 )     (f )
Deferred income tax credits
    (7,978 )     (8,738 )     (a )
Storm damage reserves
    (8,737 )     (8,341 )     (e )
Accelerated cost recovery
          (1,256 )     (g )
Property damage reserves
    (1,000 )     (1,000 )     (e )
Injury and damage reserves
    66       (123 )     (e )
         
Total
  $ (35,333 )   $ (28,752 )        
         
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 40 years.
 
(c)   Amortized over 10 years ending in 2011.
 
(d)   Transferred to plant in service in the December 2005 fuel cost recovery case. Previously being amortized over 21 months ending in July 2006.
 
(e)   Recorded and relieved upon the occurrence of a loss.
 
(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 ended in May 2005.
     In the event that a portion of the Company’s operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are currently reflected in rates.

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Revenues
Energy revenues and other 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 these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
     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 includes the cost of purchased emission allowances as they are used. See Note 3 under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.
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 one percent to five 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. The amounts recorded for manufacturer’s tax credits were not material for any period presented.
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 Allowance for Funds Used During Construction (AFUDC).
     The Company’s property, plant, and equipment consisted of the following at December 31:
                 
    2005     2004  
    (in thousands)  
Generation
  $ 416,318     $ 354,105  
Transmission
    150,126       148,199  
Distribution
    411,966       389,074  
General
    54,846       53,981  
     
Plant in service
  $ 1,033,256     $ 945,359  
 
     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 Georgia PSC 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.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.5 percent in 2005, 2.8 percent in 2004, and 2.9 percent in 2003. Depreciation studies are conducted periodically to update the composite rates and are filed with the Georgia PSC. As ordered by the Georgia PSC, the Company lowered its depreciation rates in June 2005. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost — together with the cost of removal, less salvage—is charged to 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.

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     In the Company’s 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 2005, 2004, and 2003, the Company amortized $1.3 million, $3.0 million, and $3.0 million, respectively. See Note 3 under “Retail Regulatory Matters — Rate Plans” 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. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations 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 or Interpretation No. 47.
     The Company has retirement obligations related to various landfill sites, a rail line, and underground storage tanks. As a result of the implementation of Interpretation No. 47, the Company recognized additional asset retirement obligations (and assets) of $3.3 million, primarily related to asbestos removal. 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 the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. 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 Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Georgia PSC, and are reflected in the balance sheets.
     Details of the asset retirement obligations included in the balance sheets are as follows:
                 
    2005     2004  
    (in thousands)  
Balance beginning of year
  $ 3,870     $ 4,220  
Liabilities incurred
    3,924        
Liabilities settled
    (602 )     (598 )
Accretion
    275       248  
 
Balance end of year
  $ 7,467     $ 3,870  
 
     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $7.1 million.
Allowance for Funds Used During Construction
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 8.29 percent in 2005, 6.11 percent in 2004, and 4.22 percent in 2003. AFUDC as a percent of net income was 10.0 percent in 2005, 13.5 percent in 2004, and 1.4 percent in 2003.
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

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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 “Retail Regulatory Matters — 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 facilities and other property. As part of the 2005 retail rate plan approved by the Georgia PSC (2005 Retail Rate Plan), the Company’s annual storm damage accrual was set at $0.3 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 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.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.
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.
     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact on net income of fair-value accounting for options granted is as follows:
                         
    As     Option     Pro  
    Reported     Impact     Forma  
    (in thousands)  
2005
  $ 29,933     $ (304 )   $ 29,629  
2004
    24,232       (251 )     23,981  
2003
    23,459       (270 )     23,189  
 
     The estimated fair values of stock options granted in 2005, 2004, and 2003 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:
                         
    2005     2004     2003  
Interest rate
    3.9 %     3.1 %     2.7 %
Average expected life of stock options (in years)
    5.0       5.0       4.3  
Expected volatility of common stock
    17.9 %     19.6 %     23.6 %
Expected annual dividends on common stock
  $ 1.43     $ 1.40     $ 1.37  
Weighted average fair value of stock options granted
  $ 3.90     $ 3.29     $ 3.59  
 

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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. 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 or are recoverable through the Georgia PSC approved fuel hedging program as discussed below. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, as appropriate until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges 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 limits the recovery of losses on financial hedging positions through the fuel clause to 10 percent of the Company’s annual natural gas/oil budget. These hedging position limits were $1.1 million for 2003, $2.7 million for 2004, and $5.1 million for 2005 and will be $7.4 million for 2006. 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:
               
2005
  $ 233     $ 232  
2004
  $ 233     $ 235  
     The fair values for long-term debt were based on either closing market prices or closing prices of comparable instruments.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, 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.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. 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. Due to the merger of the Company with and into Georgia Power, a liability of $0.9 million was accrued for special termination benefits provided by the Company’s supplemental executive retirement plan. See Note 3 under “Retail Regulatory Matters — Merger” for

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additional information. 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, 2006, postretirement trust contributions are expected to total approximately $1.3 million.
     The measurement date for plan assets and obligations is September 30 for each year presented.
Pension Plans
The total accumulated benefit obligation for the pension plans was $109.6 million in 2005 and $95.5 million in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:
                 
    Projected  
    Benefit Obligations  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 103,564     $ 94,789  
Service cost
    2,691       2,478  
Interest cost
    5,814       5,551  
Benefits paid
    (4,893 )     (4,575 )
Actuarial loss and employee transfers
    8,835       5,162  
Amendments
    475       159  
Contractual termination benefits
    898        
 
Balance at end of year
  $ 117,384     $ 103,564  
 
                 
    Plan Assets
    2005     2004
    (in thousands)  
Balance at beginning of year
  $ 48,556     $ 47,490  
Actual return on plan assets
    7,040       3,939  
Benefits paid
    (4,186 )     (4,060 )
Employee transfers
    2,239       1,187  
 
Balance at end of year
  $ 53,649     $ 48,556  
 
     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $104.3 million and $13.1 million, respectively. All plan assets are related to the qualified plan.
     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 were invested as follows:
                         
    Plan Assets
    Target     2005     2004
 
Domestic equity
    36 %     40 %     36 %
International equity
    24       24       20  
Fixed income
    15       17       26  
Real estate
    15       13       10  
Private equity
    10       6       8  
 
Total
    100 %     100 %     100 %
 
     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:
                 
    2005     2004  
    (in thousands)  
Funded status
  $ (63,735 )   $ (55,008 )
Unrecognized prior service cost
    6,374       6,664  
Unrecognized net loss
    29,194       26,929  
 
Accrued liability recognized in the balance sheets
  $ (28,167 )   $ (21,415 )
 
     The accrued pension liability is reflected in the balance sheets in the following line items:
                 
    2005     2004  
    (in thousands)  
Employee benefit obligations
  $ (33,768 )   $ (26,601 )
Other property and investments other
    1,442       1,634  
Accumulated other comprehensive income
    4,159       3,552  
 
Accrued liability recognized in the balance sheets
  $ (28,167 )   $ (21,415 )
 
     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

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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, 2005.
     Components of the pension plans’ net periodic cost were as follows:
                         
    2005     2004     2003  
    (in thousands)
Service cost
  $ 2,691     $ 2,479     $ 2,175  
Interest cost
    5,814       5,551       5,409  
Expected return on plan assets
    (3,931 )     (4,047 )     (4,186 )
Recognized net loss
    893       532       152  
Net amortization
    764       753       740  
Contractual termination benefits
    898              
 
Net pension cost
  $ 7,129     $ 5,268     $ 4,290  
 
     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, 2005, estimated benefit payments were as follows:
         
    (in thousands)  
2006
  $ 5,293  
2007
    5,441  
2008
    5,565  
2009
    5,851  
2010
    6,083  
2011 to 2015
  $ 35,296  
 
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  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 38,965     $ 37,249  
Service cost
    592       546  
Interest cost
    2,191       2,094  
Benefits paid
    (1,909 )     (1,459 )
Actuarial loss (gain) and amendments
    2,480       535  
 
Balance at end of year
  $ 42,319     $ 38,965  
 
                 
    Plan Assets  
    2005     2004  
    (in thousands)  
Balance at beginning of year
  $ 13,354     $ 11,275  
Actual return on plan assets
    1,598       1,329  
Employer contributions
    2,809       2,209  
Benefits paid
    (1,909 )     (1,459 )
 
Balance at end of year
  $ 15,852     $ 13,354  
 
     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 were invested as follows:
                         
    Plan Assets
    Target     2005     2004  
 
Domestic equity
    52 %     52 %     51 %
International equity
    11       12       14  
Fixed income
    30       31       30  
Real estate
    4       3       3  
Private equity
    3       2       2  
 
Total
    100 %     100 %     100 %
 
     The accrued postretirement costs recognized in the balance sheets were as follows:
                 
    2005     2004  
    (in thousands)  
Funded status
  $ (26,467 )   $ (25,611 )
Unrecognized transition obligation
    3,456       3,950  
Unamortized prior service cost
    1,537       1,651  
Unrecognized net loss
    12,275       10,986  
Fourth quarter contributions
    1,485       1,261  
 
Accrued liability recognized in the Balance Sheets
  $ (7,714 )   $ (7,763 )
 

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     Components of the postretirement plans’ net periodic cost were as follows:
                         
    2005     2004     2003  
            (in thousands)          
Service cost
  $ 592     $ 546     $ 493  
Interest cost
    2,191       2,094       2,082  
Expected return on plan assets
    (881 )     (845 )     (732 )
Recognized net loss
    474       205       91  
Net amortization
    608       756       756  
 
Net postretirement cost
  $ 2,984     $ 2,756     $ 2,690  
 
     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 and for the year ended December 31, 2005 by approximately $0.2 million and $0.5 million, respectively, and is expected to have a similar impact on future expenses.
     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)        
2006
  $ 1,996     $ (179 )   $ 1,817  
2007
    2,183       (205 )     1,978  
2008
    2,379       (229 )     2,150  
2009
    2,582       (252 )     2,330  
2010
    2,778       (273 )     2,505  
2011 to 2015
  $ 15,440     $ (1,868 )   $ 13,572  
 
Actuarial Assumptions
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:
                         
    2005   2004   2003
 
Discount
    5.50 %     5.75 %     6.00 %
Annual salary increase
    3.00       3.50       3.75  
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 APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, 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, 2005 as follows:
                 
    1 Percent     1 Percent  
    Increase     Decrease
    (in thousands)  
Benefit obligation
  $ 3,273     $ 2,382  
Service and interest costs
    204       180  
 
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 2005, 2004, and 2003 were $1.2 million, $1.1 million, and $1.1 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

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environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, 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 pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, 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 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 certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added the Company as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plant Kraft. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and the Company has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.
     The Company believes 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 financial condition if such costs are not recovered through regulated rates.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based

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rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service area involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and the Company be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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. 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.
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. In January 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.

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Retail Regulatory Matters
Merger
On December 13, 2005, Georgia Power and the Company entered into a merger agreement, under which the Company will merge with and into Georgia Power, with Georgia Power continuing as the surviving corporation (the Merger). Pursuant to the Merger agreement, at the effective time of the Merger each share of Georgia Power common stock will remain issued and outstanding; each share of Georgia Power preferred stock currently issued and outstanding will have been redeemed prior to the Merger; the issued and outstanding shares of the Company’s common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of Georgia Power common stock; and each share of the Company’s preferred stock issued and outstanding immediately prior to the Merger will be converted into the right to receive one share of a new series of Georgia Power Class A Preferred Stock. The Merger must be approved by the preferred shareholders of the Company, and is subject to the receipt of certain regulatory approvals from the FERC, the Georgia PSC, and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to occur by July 2006.
     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, Georgia Power and the Company filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, Georgia Power and the Company are seeking the approval of the Georgia PSC with respect to the following matters:
  the transfer of the Company’s generating facilities and certification of the generating facilities as Georgia Power assets;
 
  amendments to Georgia Power’s Integrated Resource Plan to add the current customers and generating facilities of the Company;
 
  the transfer of the Company’s assigned service territory to Georgia Power;
 
  adoption of Georgia Power’s service rules and regulations to the current Savannah Electric customers;
 
  new fuel rate and base rate schedules that would apply to Georgia Power’s sale of electricity to the current company customers; and
 
  the issuance of additional shares of Georgia Power common stock to Southern Company in exchange for Southern Company’s shares of the Company’s common stock.
Rate Plans
In November 2004, the Company filed a rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in total retail revenues, effective January 1, 2005 to cover the cost of new generation and PPAs, higher operating and maintenance expenses, and continued investment in new transmission and distribution facilities to support growth and ensure reliability. The requested increase was based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent.
     On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for the Company ending May 31, 2008, (2005 Retail Rate Plan). Under the terms of the 2005 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 9.75 percent to 11.75 percent. Two-thirds of any earnings above 11.75 percent will be applied to rate refunds with the remaining one-third retained by the Company. Retail base revenues increased in June 2005 by approximately $9.6 million, or 5.1 percent, on an annual basis. If the Merger is not completed, the Company would be required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued. In connection with the Merger, Georgia Power has requested Georgia PSC approval of a “merger transition charge” that would be used to adjust the Company’s existing base rates to more closely match the existing base rates for Georgia Power. The merger transition charge would remain in effect until the completion of Georgia Power’s next base rate case in 2007 that would be effective on January 1, 2008.
     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. 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.

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     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 were used to amortize the deferred amounts to purchase power expense, with the remainder retained by the Company. The Company also had discretionary authority to amortize up to an additional $1.5 million annually. Through May 31, 2005, the Company had amortized all of the deferred purchased power costs.
Fuel Hedging Program
The Georgia PSC approved a natural gas and oil procurement and hedging program that allows the Company to use financial instruments to hedge price and commodity risk. The order limits the program in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including net losses subject to certain limits, are recovered through the fuel cost recovery clause. Annual net financial gains from the hedging program are shared, with the retail customers receiving 75 percent and the Company retaining 25 percent of the total net gains. Such net gains totaled $10.5 million in 2005, of which the Company has retained $2.6 million.
Fuel Cost Recovery
On August 19, 2005, the Company filed a request with the Georgia PSC for a fuel cost recovery rate increase. On November 10, 2005, the Georgia PSC voted to approve the Company’s request to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs. Fuel revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the customer fuel rates will have no significant effect on the Company’s net income, but is expected to increase annual cash flow by approximately $52.4 million.
     As a result of recent increases in fuel costs, the Georgia PSC ordered the Company to file a new fuel case on or before January 17, 2006. In connection with the Merger, the Company requested, and the Georgia PSC agreed to postpone the January 2006 filing. Instead, the Company and Georgia Power plan to jointly file a fuel case in March 2006 that would seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined generating fleet. The new fuel cost recovery rate would be paid by all Georgia Power customers, including the existing customers of the Company, following the Merger. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.
     In a separate proceeding on August 2, 2005, the Georgia PSC approved its staff recommendation to initiate an investigation of the Company’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. The Company and Georgia Power are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.
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, which was then under construction. 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 construction 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

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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. See “FERC Matters — Intercompany Interchange Contract” herein for additional information.
     In December 2004 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 approximately $3 million is attributable to the Company and reduced the Company’s 2004 net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Combined Cycle Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. In connection with the Company’s 2005 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates.
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. In addition, the Company and Georgia Power jointly acquired the Plant McIntosh Combined Cycle Units 10 and 11 construction project in 2004. The units, which have a total capacity of 1,319 megawatts, began operation in June 2005. The Company’s amount of investment in the jointly owned Plant McIntosh facilities and related accumulated depreciation at December 31, 2005 were $135 million and $15 million, respectively. The Company’s proportionate share of its combustion turbine and combined cycle plant operating expenses is included in the 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, 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.
     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 is reimbursing Southern Power for the remaining balance of the deferred tax of $1.0 million as it is reflected in Southern Power’s future taxable income. At December 31, 2005, the payable to Southern Power is included in the Company’s balance sheet under Affiliated Accounts Payable and Other Deferred Credits and totaled $0.3 million and $0.7 million, respectively.
     At December 31, 2005, tax-related regulatory assets and liabilities were $11.5 million and $8.0 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:
                         
    2005     2004     2003  
    (in thousands)  
Federal —
                       
Currently payable
  $ (7,120 )   $ 246     $ 12,074  
Deferred
    22,430       12,171       1,299  
 
 
    15,310       12,417       13,373  
 
State —
                       
Currently payable
    (1,683 )     691       2,791  
Deferred
    3,362       1,270       (646 )
 
 
    1,679       1,961       2,145  
 
Total
  $ 16,989     $ 14,378     $ 15,518  
 

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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:
                 
    2005     2004  
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 103,991     $ 94,124  
Property basis differences
    (95 )     (845 )
Other
    33,301       13,539  
 
Total
    137,197       106,818  
 
Deferred tax assets:
               
Pension and other benefits
    22,005       17,353  
Other comprehensive income
    1,820       1,605  
Other
    11,979       14,098  
 
Total
    35,804       33,056  
 
Total deferred tax liabilities, net
    101,393       73,762  
Portion included in current assets, net
    18,031       16,317  
 
Accumulated deferred income taxes in the Balance Sheets
  $ 119,424     $ 90,079  
 
     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 2005, 2004, and 2003. At December 31, 2005, 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:
                         
    2005     2004     2003  
Federal statutory tax rate
    35 %     35 %     35 %
State income tax, net of Federal income tax benefit
    2       3       4  
Other
    (3 )     (2 )     1  
 
Effective income tax rate
    34 %     36 %     40 %
 
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. At December 31, 2005 and 2004, the Company had capitalized lease obligations for its Plant Kraft coal unloading dock and its vehicles of $5.1 million and $5.8 million, respectively. However, for ratemaking purposes, these obligations are treated as operating leases and, as such, lease payments are charged to expense as incurred. The annual expense incurred for 2005, 2004, and 2003 for the Plant Kraft coal unloading dock was $0.5 million. The annual expense for the vehicles was $0.6 million in 2005, $0.5 million in 2004, and $0.4 million in 2003.
Securities Due Within One Year
At December 31, 2004, the Company was subject to a first mortgage bond improvement (sinking) fund requirement of $200,000, or 1 percent of the outstanding bonds authenticated under the first mortgage bond indenture, other than those issued to collateralize pollution control and other obligations. This requirement was satisfied by pledging additional property equal to 1 2/3 times the requirement.
     The outstanding first mortgage bonds mature in May 2006; therefore, at December 31, 2005, there is no remaining sinking fund requirement. Maturities through 2010 applicable to long-term debt are as follows: $21.0 million in 2006; $1.0 million in 2007; $46.0 million in 2008; $0.8 million in 2009; and $0.5 million in 2010.
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 2006, credit arrangements with banks totaled $80 million, of which $60 million expires at various times in 2006 and the remaining $20 million expires in 2008. The facilities expiring in 2006 contain two-year term out provisions and the facility that expires in 2008 contains a one-year term out provision.
     In connection with these credit arrangements, the

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Company agrees to pay commitment fees based on the unused portions of the commitments. Commitment fees are one-eighth of 1 percent or less 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 in compliance with all such covenants.
     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, 2005, the Company had $49.9 million in commercial paper and $8.9 million in extendible commercial notes outstanding. During 2005, the peak amount of short-term debt outstanding was $63.7 million and the average amount outstanding was $41.9 million. The average annual interest rate on short-term debt was 3.4 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, 2005, the amount of variable rate obligations outstanding requiring liquidity support was $6.7 million.
Financial Instruments
The Company enters into energy related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the direction of the Georgia PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in any period presented.
     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:
         
    Amounts  
 
    (in thousands)  
Regulatory liabilities, net
  $ 8,752  
Other comprehensive income
     
Net income
    (4 )
 
Total fair value
  $ 8,748  
 
 
     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 2008.
     The Company enters into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives are generally structured to mirror the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.
     At December 31, 2005, the Company had $44 million notional amount of interest rate swaps accounted for as cash flow hedges outstanding with net fair value gains of $0.9 million as follows:
                         
    Weighted Average           Fair  
    Fixed           Value  
    Rate   Notional     Gain/  
Maturity   Paid   Amount     (Loss)  
            (in millions)  
2007
    2.50%*     $ 14.0     $ 0.3  
2016
    4.69%     $ 30.0     $ 0.6  
 
*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 all periods presented, the amounts reclassified from other comprehensive income to interest expense were not material. For 2006, pre-tax

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gains of approximately $0.1 million are expected to be reclassified from other comprehensive income to interest expense.
Common Stock Dividend Restrictions
The Company’s first mortgage bond indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 2005, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the indenture.
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated to total $44.7 million in 2006, $33.5 million in 2007, and $55.8 million in 2008. 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. 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, 2005, 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 $36 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. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below for natural gas represent estimates based on New York Mercantile Exchange future prices at December 31, 2005.
     Total estimated minimum long-term obligations at December 31, 2005 were as follows:
                 
    Natural        
Year   Gas     Coal  
    (in thousands)  
2006
  $ 60,829     $ 60,615  
2007
    32,101       11,073  
2008
    19,187        
2009
    43,943        
2010
    43,943        
2011 and thereafter
    362,804        
 
Total commitments
  $ 562,807     $ 71,688  
 
     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

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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 through 2009.
     Estimated total long-term obligations at December 31, 2005 were as follows:
         
Year   Commitments  
    (in thousands)  
2006
  $ 13,240  
2007
    13,257  
2008
    13,274  
2009
    13,286  
 
Total commitments
  $ 53,057  
 
Operating Leases
The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.9 million for 2005, $0.9 million for 2004, and $0.9 million for 2003. Of these amounts, $0.8 million in each year related to railcar leases and coal dozers and were recoverable through the Company’s fuel cost recovery clause.
     At December 31, 2005, estimated future minimum lease payments for noncancelable operating leases were as follows:
                         
Year   Railcars     Other     Total  
    (in thousands)  
2006
  $ 429     $ 480     $ 909  
2007
    429       388       817  
2008
    429       327       756  
2009
    429       219       648  
2010
    429             429  
2011 and thereafter
    3,179             3,179  
 
Total minimum payments
  $ 5,324     $ 1,414     $ 6,738  
 
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, 2005, 91 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 2003 to 2005 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, 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  
Options granted
    123,278       32.70  
Options canceled
    (4,544 )     27.10  
Options exercised
    (154,033 )     21.85  
 
Balance at December 31, 2005
    517,984     $ 27.53  
 
                 
Options exercisable:
               
At December 31, 2003
            251,576  
At December 31, 2004
            318,250  
At December 31, 2005
            282,133  
 
     The following table summarizes information about options outstanding at December 31, 2005:
                         
    Dollar Price  
    Range of Options  
    13-21     21-28     28-35  
 
Outstanding:
                       
Shares (in thousands)
    58       227       233  
Average remaining life (in years)
    4.2       6.4       8.6  
Average exercise price
  $ 17.35     $ 26.39     $ 31.18  
Exercisable:
                       
Shares (in thousands)
    58       189       35  
Average exercise price
  $ 17.35     $ 26.07     $ 29.53  
 

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report
9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2005 and 2004 are as follows:
                         
                    Net Income
    Operating   Operating   after Preferred
Quarter Ended   Revenues   Income   Stock Dividends
    (in thousands)
March 2005
  $ 88,588     $ 3,944     $ 1,020  
June 2005
    96,588       15,331       7,728  
September 2005
    150,983       35,146       19,693  
December 2005
    108,835       6,157       1,492  
                         
March 2004
  $ 72,321     $ 8,032     $ 2,833  
June 2004
    91,149       13,971       6,784  
September 2004
    107,889       24,541       13,416  
December 2004
    85,601       6,284       1,199  
 
     The Company’s business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Savannah Electric and Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands)
  $ 444,994     $ 356,960     $ 315,117     $ 297,006     $ 282,926  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 29,933     $ 24,232     $ 23,459     $ 21,319     $ 21,495  
Cash Dividends on Common Stock (in thousands)
  $ 26,700     $ 23,200     $ 23,000     $ 22,700     $ 21,700  
Return on Average Common Equity (percent)
    12.75       11.67       13.07       12.16       12.36  
Total Assets (in thousands)
  $ 912,801     $ 812,591     $ 706,259     $ 644,923     $ 617,282  
Gross Property Additions (in thousands)
  $ 52,314     $ 126,133     $ 40,242     $ 32,481     $ 31,296  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 237,548     $ 232,156     $ 183,089     $ 175,949     $ 174,624  
Preferred stock
    43,909       43,938                    
Mandatorily redeemable preferred securities
                      40,000       40,000  
Long-term debt
    217,033       237,769       222,493       168,052       160,709  
 
Total (excluding amounts due within one year)
  $ 498,490     $ 513,863     $ 405,582     $ 384,001     $ 375,333  
 
Capitalization Ratios (percent) :
                                       
Common stock equity
    47.7       45.2       45.1       45.8       46.5  
Preferred stock
    8.8       8.6                    
Mandatorily redeemable preferred securities
                      10.4       10.7  
Long-term debt
    43.5       46.2       54.9       43.8       42.8  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Security Ratings:
                                       
First Mortgage Bonds —
                                       
Moody’s
    A1       A1       A1       A1       A1  
Standard and Poor’s
    A+       A+       A+       A+       A+  
Preferred Stock —
                                       
Moody’s
  Baa1     Baa1     Baa1     Baa1     Baa1  
Standard and Poor’s
  BBB+     BBB+     BBB+     BBB+     BBB+  
Unsecured Long-Term Debt —
                                       
Moody’s
    A2       A2       A2       A2       A2  
Standard and Poor’s
    A       A       A       A       A  
 
Customers (year-end) :
                                       
Residential
    128,036       124,789       122,128       120,131       117,199  
Commercial
    18,636       17,964       17,102       16,512       16,121  
Industrial
    84       89       90       81       76  
Other
    607       533       506       494       474  
 
Total
    147,363       143,375       139,826       137,218       133,870  
 
Employees (year-end)
    560       563       549       550       550  
 

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Savannah Electric and Power Company 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands) :
                                       
Residential
  $ 202,933     $ 164,889     $ 143,461     $ 137,767     $ 123,394  
Commercial
    150,825       120,907       106,433       103,293       100,484  
Industrial
    54,565       44,600       38,767       32,434       34,852  
Other
    13,228       11,370       10,146       9,731       9,516  
 
Total retail
    421,551       341,766       298,807       283,225       268,246  
Sales for resale — non-affiliates
    5,126       5,035       5,653       6,354       8,884  
Sales for resale — affiliates
    10,536       6,130       6,499       4,075       3,205  
 
Total revenues from sales of electricity
    437,213       352,931       310,959       293,654       280,335  
Other revenues
    7,781       4,029       4,158       3,352       2,591  
 
Total
  $ 444,994     $ 356,960     $ 315,117     $ 297,006     $ 282,926  
 
Kilowatt-Hour Sales (in thousands) :
                                       
Residential
    1,923,357       1,899,462       1,753,885       1,755,967       1,648,102  
Commercial
    1,565,780       1,539,536       1,461,191       1,454,674       1,379,583  
Industrial
    804,894       840,572       860,840       791,422       784,688  
Other
    136,013       142,732       137,158       137,913       133,210  
 
Total retail
    4,430,044       4,422,302       4,213,074       4,139,976       3,945,583  
Sales for resale — non-affiliates
    83,876       131,259       162,469       150,795       111,145  
Sales for resale — affiliates
    178,251       142,871       185,202       125,882       87,799  
 
Total
    4,692,171       4,696,432       4,560,745       4,416,653       4,144,527  
 
Average Revenue Per Kilowatt-Hour (cents) :
                                       
Residential
    10.55       8.68       8.18       7.85       7.49  
Commercial
    9.63       7.85       7.28       7.10       7.28  
Industrial
    6.78       5.31       4.50       4.10       4.44  
Total retail
    9.52       7.73       7.09       6.84       6.80  
Sales for resale
    5.97       4.07       3.50       3.77       6.08  
Total sales
    9.32       7.51       6.82       6.65       6.76  
Residential Average Annual Kilowatt-Hour Use Per Customer
    15,208       15,388       14,493       14,771       14,150  
Residential Average Annual Revenue Per Customer
  $ 1,605     $ 1,336     $ 1,185     $ 1,159     $ 1,059  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    898       765       788       788       788  
Maximum Peak-Hour Demand (megawatts) :
                                       
Winter
    859       805       882       738       758  
Summer
    983       949       904       921       846  
Annual Load Factor (percent)
    54.5       56.3       56.8       54.5       55.9  
Plant Availability Fossil-Steam (percent)
    86.8       77.1       83.3       81.4       81.2  
 
Source of Energy Supply (percent) :
                                       
Coal
    39.9       41.2       44.7       44.4       50.5  
Oil and gas
    11.1       1.9       2.7       4.2       4.0  
Purchased power -
                                       
From non-affiliates
    3.7       5.4       3.1       3.1       5.3  
From affiliates
    45.3       51.5       49.5       48.3       40.2  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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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 consolidated balance sheets of Southern Power Company and subsidiaries (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included 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, such consolidated financial statements (pages II-348 to II-361) present fairly, in all material respects, the financial position of Southern Power Company and subsidiaries at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power Company and Subsidiary Companies 2005 Annual Report
OVERVIEW
Business Activities
Southern Power Company and its wholly-owned subsidiaries (the Company) construct, own, and manage the Southern Company’s competitive generation assets and sell electricity at market-based rates in the Super-Southeast wholesale market. The Company focused on executing its regional strategy in 2005 by signing purchased power agreements (PPAs) with investor owned utilities, electric cooperatives, and municipal suppliers for generation assets in the Southeast.
     In June 2005, the Company acquired all of the outstanding general and limited partnership interests of Oleander Power Project, LP (Oleander) from subsidiaries of Constellation Energy Group, Inc. Oleander owns a 628 megawatt (MW) dual-fueled simple cycle combustion turbine plant in Cocoa, Florida, and has PPAs with Florida Power & Light (FPL) and Seminole Electric Cooperative, Inc. (Seminole) covering the entire output of the plant.
     In December 2005, the Company and the Orlando Utilities Commission (OUC) entered into definitive project agreements to develop an integrated coal gasification combined cycle (IGCC) project on OUC’s Stanton Energy Center site in Orlando, Florida. In addition, in February 2006, the Company signed a cooperative agreement with the U.S. Department of Energy (DOE) that provides up to $235 million in funding to be applied by the joint owners for the construction and demonstration of the gasification portion of this project.
     As of December 31, 2005, the Company had 5,403 MWs in commercial operation. The weighted average duration of the Company’s wholesale contracts generally exceeds 10 years, which reduces remarketing risk. However, the Company continues to face challenges at the federal regulatory level relative to market power and affiliate transactions.
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 several key performance indicators. These indicators consist of plant availability, peak season equivalent forced outage rate (EFOR), and net income. 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). Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s actual performance in 2005 surpassed targets in these key performance areas. See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance.
Earnings
The Company’s 2005 earnings were $115 million, a $3 million increase over 2004. The 2005 increase is primarily attributed to the acquisition of Oleander in June 2005 and additional revenues associated with energy margins from fully contracted units, which were partially offset by the expiration of PPAs at Plant Dahlberg. In addition, interest expense increased in connection with the Oleander acquisition as well as the reduction in interest capitalized related to the conclusion of the Company’s initial construction program.
     The Company’s earnings decreased $44 million in 2004 and increased $101 million in 2003. These changes were primarily the result of a one time $50 million gain in May 2003 from the termination of PPAs with Dynegy Inc. (Dynegy). In addition, Plant Stanton A, Plant Franklin Unit 2, and Plant Harris Unit 1 and 2 were all placed into service in 2003 and related revenues from PPAs or opportunity sales began. See Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project” for additional information on the Dynegy transaction.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
RESULTS OF OPERATIONS
A condensed income statement is as follows:
                                 
                    Increase (Decrease)        
    Amount               From Prior Year
 
    2005     2005     2004     2003  
   
            (in thousands)          
Operating revenues
  $ 781,004     $ 79,693       $ 19,531     $ 383,012  
 
Fuel
    209,008       81,905       11,847       17,291  
Purchased power
    160,056       (28,400 )     3,155       131,638  
Other operation and maintenance
    80,805       5,610       12,954       33,890  
Depreciation and amortization
    54,254       3,093       12,149       20,693  
Taxes other than income taxes
    13,314       2,041       4,608       2,390  
 
Total operating expenses
    517,437       64,249       44,713       205,902  
 
Operating income
    263,567       15,444       (25,182 )     177,110  
Other income, net
    2,379       (29 )     4,002       2,988  
Less —
                               
Interest expense and other, net
    79,322       13,234     34,380     22,822
Income taxes
    71,833       (1,102 )     (12,286 )     56,764  
Cumulative effect of accounting
                (367 )     367  
 
Net Income
  $ 114,791     $ 3,283       $(43,641 )   $ 100,879  
 
Revenues
Operating revenues in 2005 were $781.0 million, a $79.7 million (11.4 percent) increase from 2004. This increase was primarily due to PPAs acquired in the Oleander acquisition, a new PPA with Flint Energies (Flint EMC), and a full year of revenue from PPAs with Georgia Power at Plant Franklin Unit 2 and Plant Harris Unit 2. The Georgia Power PPA for Plant Franklin Unit 2 had a scheduled sales increase in June 2004, while the PPA for Plant Harris Unit 2 became effective June 2004. These increases were partially offset by the expiration of PPAs at Plant Dahlberg. See FUTURE EARNING POTENTIAL – “Power Sales Agreements” and Note 2 to the financial statements under “Oleander Acquisition” for additional information.
     Operating revenues in 2004 were $701.3 million, a $19.5 million (2.9 percent) increase from 2003. The increase was primarily related to a full year of revenues under PPAs from new units. Plant Harris Units 1 and 2 and Plant Franklin Unit 2 were placed in service in June 2003. Plant Stanton A was placed in service in October 2003.
     Operating revenues in 2003 were $681.8 million, a $383.0 million (128.2 percent) increase from 2002. In 2003, operating revenues increased due to a one time gain from a termination settlement with Dynegy and new PPAs or opportunity sales from four new units placed into service. Also contributing to this increase was a $9.9 million dollar increase in service and fee revenues from various electric membership cooperative (EMC) contracts.
     Capacity revenues are an integral component of the Company’s PPAs with both affiliate and non-affiliate customers and represent the greatest contribution to net income. Energy under PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Details of these PPA capacity and energy revenues are as follows:
                         
    2005     2004     2003
 
            (thousands)          
 
Capacity revenues
                       
Affiliates
  $ 278,221     $ 247,914     $ 163,341  
Non-Affiliates
    68,645       73,980       54,064  
 
                 
Total
    346,866       321,894       217,405  
Energy revenues
                       
Affiliates
    254,844       124,837       103,340  
Non-Affiliates
    141,496       80,825       55,906  
 
                 
Total
    396,340       205,662       159,246  
     
Total PPA revenues
  $ 743,206     $ 527,556     $ 376,651  
     
     Revenues from sales to affiliated and non-affiliated companies that are not covered by PPAs are made in accordance with the Intercompany Interchange Contract (IIC), 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
Expenses
Fuel and Purchased Power
In 2005, fuel expense increased by $81.9 million or 64.4 percent. The increase was driven by a 54.2 percent increase in the average cost of natural gas per decatherm. In 2004, fuel expense increased by $11.8 million or 10.3 percent primarily due to increased gas transportation expenses associated with Plant Harris Unit 2 prior to its commitment with Georgia Power. The average cost of natural gas per decatherm also increased 8.3 percent from 2003 to 2004. In 2003, fuel expense increased $17.3 million or 17.7 percent primarily due to the operation of Plant Wansley Units 6 and 7 for a full year, as well as the commencement of commercial operations of Plant Franklin Unit 2 and Plant Harris Units 1 and 2 in June 2003. 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. The average cost of natural gas per decatherm increased 24 percent from 2002 to 2003.
     A significant upward trend in the cost of natural gas has emerged since 2003, and volatility in this market is expected to continue. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2005 and 2004 hurricanes result in an immediate market response; however, the long-term 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 decreased $28.4 million in 2005, primarily due to increased PPA commitments for the Company’s generating resources beginning in June 2004. Previously, capacity from some of these units was sold into the short-term market and related energy sales were sometimes served with short-term power purchases from both affiliates and non-affiliates when market costs were lower than the cost of self-generation.
     Purchased power increased $3.2 million in 2004 over 2003, consisting of a $15.4 million increase for non-affiliates and a $12.3 million decrease for affiliates 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. Purchased power increased by $131.6 million in 2003 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.
     The amount of purchased power expenses between affiliates and non-affiliates 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 generation owned by the Company, affiliate-owned generation, or external purchases.
Operations and Maintenance
Other operations and maintenance, depreciation and amortization expenses, and taxes other than income taxes all increased during the period from 2002 through 2005. These year-to-year increases are primarily the result of new generating units. In 2002, Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 were placed into service. Four more units were placed in service in 2003 including Plant Franklin Unit 2, Plant Harris Units 1 and 2, and Plant Stanton A. Plant Oleander was acquired in June 2005.
Interest Expense
Interest expense has increased by $13.2 million, $34.4 million, and $22.8 million in 2005, 2004, and 2003, respectively. These increases were primarily the result of additional debt incurred for the Oleander acquisition, and a lower percentage of interest costs being capitalized as projects reached completion, were sold, or were suspended. Plant McIntosh Units 10 and 11 were transferred to Georgia Power and Savannah Electric and construction was suspended on Plant Franklin Unit 3 during 2004, effectively ceasing all capitalized interest. For additional information, see FUTURE EARNINGS POTENTIAL — “Construction Projects – Plant Franklin Unit 3” and Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project.”
Other Income and Expense
The increases in other income net, in 2004 and 2003 were primarily the result of realized gains and losses on derivative energy contracts. See FINANCIAL

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
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 party to long-term contracts that are generally 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 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 including regulatory matters such as 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.
Power Sales Agreements
The Company’s sales are primarily through long-term PPAs. 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 of generating capacity in the Super Southeast, opportunities remain in certain areas.
     In February 2006, the Company entered into a PPA with Florida Municipal Power Agency (FMPA) to commence in 2007 and extend through 2022. The Company will provide FMPA with the output from a dedicated unit to be constructed at the Plant Oleander site.
     In June 2005 as part of the Oleander acquisition, the Company acquired PPAs with FPL and Seminole. The FPL PPA is for one unit and extends through the end of May 2007. The Seminole PPA is for the three remaining units at Plant Oleander and extends through the end of 2009. In February 2006, the Company signed an extension of the FPL PPA for approximately 160 MWs of capacity through May 2012. Also in February 2006, the Company signed a new PPA with Seminole for approximately 320 MWs of capacity through December 2015. See Note 2 to the financial statements under “Oleander Acquisition” for additional information.
     In August 2004, the Company entered into two PPAs with FPL. Under the PPAs, the Company will provide FPL with a total of 790 MWs of capacity annually from Plant Harris Unit 1 and Plant Franklin Unit 1 for the period from June 2010 through December 2015. A similar PPA with Progress Energy Florida (Progress) was signed in November 2004 for 350 MWs from Franklin Unit 1 for the period June 2010 through December 2015. The Florida Public Service Commission has approved these contracts.
     Also in 2004, the Company executed multiple agreements expanding its relationship with existing customers. For the years 2005 through 2009, the Company will sell approximately 130 MWs of additional wholesale capacity from existing resources to Flint EMC. The Company also agreed to a 10-year extension of the OUC PPA for Stanton Unit A.
     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 MWs 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.

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     The Company has entered into long-term power sales agreements for a portion of its generating capacity as follows:
                 
    Capacity     Initial  
Project   (megawatts)     Term (1)  
 
Affiliated
               
Franklin Unit 1
    563       6/02-5/10  
Franklin Unit 2
    623       6/03-5/11  
Wansley Units 6 & 7
    1,129       6/02-12/09  
Harris Unit 1
    625       6/03-5/10  
Harris Unit 2
    628       6/04-5/19  
 
Non-Affiliated
               
Stanton A (OUC)
    338       11/03-10/23  
Stanton A (KUA, FMPA)
    85       11/03-10/13  
GA EMC Full Requirements (2)
    62-434       2002-2009  
Oleander (FPL)
    160       6/05-5/12  
Oleander (Seminole)
    533       6/05-12/09  
Oleander (Seminole)
    320       1/10-12/15  
Oleander (FMPA)
    160       12/07-12/22  
Piedmont (PMPA) Full Requirements
    135-181       2006-2010  
Franklin Unit 1 (FPL/Progress)
    540       6/10-12/15  
Harris Unit 1 (FPL)
    625       6/10-12/15  
 
(1)   Excluding automatic renewal provisions
 
(2)   Option in 2009 to convert from full requirements to fixed capacity sale.
     Although some of the Company’s PPAs are with 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. The Company expects 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 the 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.
     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 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.
     The Company’s PPAs with non-affiliated counterparties have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard & Poor’s or Moody’s downgrades the credit ratings of such counterparty to below investment grade or 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.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates at market-based prices and 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 December 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 an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15-months. In the event that the FERC’s default mitigation measures for entities that are found

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to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, the Company, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of the Company as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving the approval of PPAs between the Company and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, 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. Such statutes and regulations 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; the Endangered Species Act; and related federal and state regulations. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also affect the Company.
     New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations. While 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.

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     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.
     Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements such as opacity and other air quality standards, 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 potential litigation against the Company cannot be predicted at this time.
Construction Projects
Integrated Gasification Combined Cycle (IGCC)
In December 2005, the Company and OUC executed definitive agreements for development of the IGCC, a project of approximately 285 MW in Orlando, Florida, adjacent to Plant Stanton Unit A, which is co-owned by the Company, OUC and others. The definitive agreements provide that the Company will own at least 65 percent of the gasifier portion of the project. OUC will own the remainder of the gasifier portion and 100 percent of the combined cycle portion of the project. OUC will make capacity payments for all of the Company’s gasifier capacity once the plant is in commercial operation. The Company will construct the project and bill OUC a fixed price for its share in the project. The Company will also manage operations after construction is completed using a joint staff of OUC and SCS employees.
     A cooperative agreement with DOE was signed in February 2006, which provides for up to $235 million in funding from the DOE to be applied by the joint owners for the construction and demonstration of the gasification portion of the project. The DOE will provide the funding in four phases throughout the development and demonstration of the gasifier. The Company’s share of the total cost related to the gasifier portion of the project is currently estimated at approximately $121 million. The IGCC project, subject to National Environmental Policy Act review and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in 2010.
Plant Franklin Unit 3
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 this matter cannot now be determined.
Other Matters
The Company is currently conducting a depreciation study to update the composite depreciation rates for its property, plant, and equipment. The impact of this possible change cannot be determined at this time.
     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. Management has reviewed and discussed the critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
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, which provide for the sale of electricity to be physically delivered in quantities within the Company’s available generating capacity to be normal sales. In accordance with FASB 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, 2005.
Cash Flow Hedge Transactions
The Company designates other derivative contracts for the sale 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.
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 were not material for the year ended December 31, 2005.
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

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the financial statements under “Plant Franklin Unit 3 Construction Project” for additional information.
New Accounting Standards
Income Taxes
In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.
Conditional Asset Retirement Obligations
Effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” The adoption of FIN 47 had no impact on the Company’s financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The major change in the Company’s financial condition during 2005 was the June acquisition of Oleander, which contributed $218 million of utility plant and working capital. See Note 2 to the financial statements under “Oleander Acquisition” for additional information. The Company has received investment grade ratings from the major rating agencies.
Sources of Capital
The Company may use operating cash flows, external funds, or equity capital from Southern Company to finance any new projects, acquisitions 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.
     The Company’s current liabilities frequently exceed current assets due to the use of short-term debt as a funding source. At December 31, 2005, the Company had approximately $27.6 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, 2005, $399 million of unused committed credit arrangements with banks. Subject to certain financial covenants, these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for the Company’s commercial paper program. See Note 5 to the financial statements under “Bank Credit Arrangements” for additional information.
     The Company’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At December 31, 2005, there was $110.7 million of commercial paper outstanding. See Note 5 to the financial statements under “Commercial Paper” for additional information.
     The issuance of all securities by the Company is generally subject to regulatory approval by the FERC. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. Additionally, with respect to the public offering of securities, the Company will be required to file registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended.
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 change to BBB- or Baa3, or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005 the maximum potential collateral requirements at BBB- or Baa3 were approximately $190 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $357 million. Generally, collateral may be provided with a 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 risk management activities. At December 31, 2005, the

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Company had no material exposure related to these agreements.
     Subsequent to December 31, 2005, the Company has entered into additional physical electricity purchases and sales contracts adding $9 million to the maximum potential collateral requirements at a credit rating of BBB and Baa2 and $17 million at BBB- or Baa3 and below.
Market Price Risk
The Company is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.
     Because energy from the Company’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the 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  
   
    2005     2004  
   
    (in thousands)  
Contracts beginning of year
  $ 9     $ 665  
Contracts realized or settled
    (168 )     (469 )
New contracts at inception
           
Current period changes (a)
    382       (187 )
 
Contracts end of year
  $ 223     $ 9  
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
     At December 31, 2005, the sources of the valuation prices were as follows:
                         
    Source of 2005 Year-End Valuation Prices  
   
    Total     Maturity  
    Fair Value     2006     2007-2008  
   
            (in thousands)  
Actively quoted
  $ 259     $ 217     $ 42  
External sources
    (36 )     (36 )      
Models and other methods
                 
 
Contracts end of year
  $ 223     $ 181     $ 42  
 
     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, 2005, the fair value of derivative energy contracts was as follows:
         
    Amounts (in thousands)  
 
Net Income
  $ 153  
Other Comprehensive Income
    70  
 
Total fair value
  $ 223  
 
     Approximately, $0.1 million, $0.3 million, and $(1.9) million of unrealized pre-tax gains (losses) were recognized in income in 2005, 2004, and 2003, 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, 2005, 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.

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Capital Requirements and Contractual Obligations
The capital program of the Company is currently estimated to be $162.3 million for 2006, $265.2 million for 2007, and $221.0 million for 2008. These amounts include estimates for potential plant acquisitions and/or new construction. 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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Southern Power Company and Subsidiary Companies 2005 Annual Report
                                         
            2007-     2009-     After        
Contractual Obligations   2006     2008     2010     2010     Total  
    (in millions)  
Long-term debt(a)
                                       
Principal
  $ 0.2     $ 1.3     $     $ 1,100.0     $ 1,101.5  
Interest
    61.6       123.1       123.1       199.8       507.6  
Operating leases
    0.7       0.9       0.6       25.1       27.3  
Purchase commitments(b)
                                       
Capital(c)
    162.3       486.2                   648.5  
Natural gas(d)
    20.9       42.0       45.7       300.1       408.7  
Long-term service agreements
    27.4       83.0       76.2       938.5       1,125.1  
 
Total
  $ 273.1     $ 736.5     $ 245.6     $ 2,563.5     $ 3,818.7  
 
(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 operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $80.8 million, $75.2 million, and $62.2 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, 2005.

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Cautionary Statement Regarding Forward-Looking Statements
The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, earnings growth, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, 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, implementation of the Energy Policy Act of 2005, 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 FERC matters;
  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;
  advances in technology;
  the ability to avoid cost overruns during the development and construction of facilities, including the IGCC;
  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 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 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 Securities and Exchange Commission.
The 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, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)  
Operating Revenues:
                       
Sales for resale —
                       
Non-affiliates
  $ 223,058     $ 266,463     $ 278,559  
Affiliates
    556,664       425,065       312,586  
Contract termination
                80,000  
Other revenues
    1,282       9,783       10,635  
 
Total operating revenues
    781,004       701,311       681,780  
 
Operating Expenses:
                       
Fuel
    209,008       127,103       115,256  
Purchased power —
                       
Non-affiliates
    57,182       76,652       61,234  
Affiliates
    102,874       111,804       124,067  
Other operations
    61,235       58,111       50,852  
Maintenance
    19,570       17,084       11,389  
Depreciation and amortization
    54,254       51,161       39,012  
Taxes other than income taxes
    13,314       11,273       6,665  
 
Total operating expenses
    517,437       453,188       408,475  
 
Operating Income
    263,567       248,123       273,305  
Other Income and (Expense):
                       
Interest expense, net of amounts capitalized
    (79,322 )     (66,088 )     (31,708 )
Other income (expense), net
    2,379       2,408       (1,594 )
 
Total other income and (expense)
    (76,943 )     (63,680 )     (33,302 )
 
Earnings Before Income Taxes
    186,624       184,443       240,003  
Income taxes
    71,833       72,935       85,221  
 
Earnings Before Cumulative Effect of Accounting Change
    114,791       111,508       154,782  
Cumulative effect of accounting change— less income taxes of $231
                367  
 
Net Income
  $ 114,791     $ 111,508     $ 155,149  
 
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, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)  
Operating Activities:
                       
Net income
  $ 114,791     $ 111,508     $ 155,149  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    68,210       65,838       47,267  
Deferred income taxes and investment tax credits, net
    24,055       23,510       22,521  
Deferred revenues
    (370 )     10,064       9,997  
Tax benefit of stock options
    686       415       130  
Hedge settlements
                (93,298 )
Other, net
    2,777       9,957       (25,787 )
Changes in certain current assets and liabilities —
                       
Receivables
    (42,355 )     (14,009 )     (7,008 )
Fossil fuel stock
    (4,316 )     2,894       5,232  
Materials and supplies
    (4,096 )     (1,715 )     (1,570 )
Other current assets
    (5,900 )     4,144       (9,675 )
Accounts payable
    41,662       (13,844 )     32,694  
Accrued taxes
    5,782       32,330       (6,939 )
Accrued interest
    535       (1,386 )     9,299  
Other current liabilities
          (306 )     236  
 
Net cash provided from operating activities
    201,461       229,400       138,248  
 
Investing Activities:
                       
Property additions
    (241,103 )     (115,606 )     (344,362 )
Sale of property to affiliates
          414,582        
Change in construction payables, net
    (124 )     (14,349 )     (16,931 )
Other
          (10,043 )      
 
Net cash provided from (used for) investing activities
    (241,227 )     274,584       (361,293 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net — affiliated
                (20,488 )
Increase (decrease) in notes payable, net
    110,692       (114,349 )     114,347  
Proceeds —
                       
Senior notes
                575,000  
Capital contributions from parent company
    5,022       2,808       5,952  
Redemptions —
                       
Senior notes
          (50,000 )      
Other long-term debt
    (200 )           (379,640 )
Capital distributions to parent company
          (113,000 )     (77,000 )
Payment of common stock dividends
    (72,400 )     (207,000 )      
Other
    (958 )           (11,802 )
 
Net cash provided from (used for) financing activities
    42,156       (481,541 )     206,369  
 
Net Change in Cash and Cash Equivalents
    2,390       22,443       (16,676 )
Cash and Cash Equivalents at Beginning of Year
    25,241       2,798       19,474  
 
Cash and Cash Equivalents at End of Year
  $ 27,631     $ 25,241     $ 2,798  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $0, $17,368 and $36,736 capitalized, respectively)
  $ 64,487     $ 52,146     $ 105,765  
Income taxes (net of refunds)
    33,751       13,313       77,993  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Power Company and Subsidiary Companies 2005 Annual Report
                 
Assets   2005     2004  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 27,631     $ 25,241  
Receivables —
               
Customer accounts receivable
    20,953       12,865  
Other accounts receivable
    93       893  
Accumulated provision for uncollectible accounts
          (350 )
Affiliated companies
    60,505       25,423  
Fossil fuel stock, at average cost
    7,221       2,904  
Materials and supplies, at average cost
    15,628       9,839  
Prepaid income taxes
          4,619  
Prepaid expenses
    10,788       8,085  
Other
    251       112  
 
Total current assets
    143,070       89,631  
 
Property, Plant, and Equipment:
               
In service
    2,030,996       1,821,434  
Less accumulated provision for depreciation
    161,358       111,200  
 
 
    1,869,638       1,710,234  
Construction work in progress
    218,812       200,903  
 
Total property, plant, and equipment
    2,088,450       1,911,137  
 
Deferred Charges and Other Assets:
               
Prepaid long-term service agreements
    46,447       34,800  
Other—
               
Affiliated
    4,496       6,455  
Other
    20,513       24,990  
 
Total deferred charges and other assets
    71,456       66,245  
 
Total Assets
  $ 2,302,976     $ 2,067,013  
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Power Company and Subsidiary Companies 2005 Annual Report
                 
Liabilities and Stockholder’s Equity   2005     2004  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 200     $ 200  
Notes payable
    110,692        
Accounts payable —
               
Affiliated
    65,262       19,265  
Other
    7,651       11,024  
Accrued taxes —
               
Income taxes
    3,477        
Other
    2,524       4,104  
Accrued interest
    29,161       28,626  
Other
    71       83  
 
Total current liabilities
    219,038       63,302  
 
Long-Term Debt:
               
Senior notes —
               
6.25% due 2012
    575,000       575,000  
4.875% due 2015
    525,000       525,000  
Other long-term debt
    1,285       1,485  
Unamortized debt discount
    (1,765 )     (2,050 )
 
Long-term debt
    1,099,520       1,099,435  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    68,535       40,212  
Deferred capacity revenues — affiliated
    37,534       39,118  
Other —
               
Affiliated
    10,792       13,333  
Other
    1,214       2  
 
Total deferred credits and other liabilities
    118,075       92,665  
 
Total Liabilities
    1,436,633       1,255,402  
 
Common Stockholder’s Equity:
               
Common stock, par value $0.01 per share —
               
Authorized - 1,000,000 shares
               
Outstanding - 1,000 shares
           
Paid-in capital
    746,243       740,535  
Retained earnings
    164,525       122,134  
Accumulated other comprehensive income (loss)
    (44,425 )     (51,058 )
 
Total common stockholder’s equity
    866,343       811,611  
 
Total Liabilities and Stockholder’s Equity
  $ 2,302,976     $ 2,067,013  
 
Commitments and Contingent Matters (See notes)
               
 
The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report
                                         
                            Other    
    Common   Paid-In   Retained   Comprehensive    
    Stock   Capital   Earnings   Income (loss)   Total
    (in thousands)
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  
Net income
                114,791             114,791  
Capital contributions from parent company
          5,708                   5,708  
Other comprehensive income (loss)
                      6,633       6,633  
Cash dividends on common stock
                (72,400 )           (72,400 )
 
Balance at December 31, 2005
  $     $ 746,243     $ 164,525     $ (44,425 )   $ 866,343  
 
 
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report
                         
    2005     2004     2003  
    (in thousands)  
Net income
  $ 114,791     $ 111,508     $ 155,149  
 
Other comprehensive income (loss):
                       
Changes in fair value of qualifying hedges, net of tax of $106, $(520), and $(7,872), respectively
    164       (920 )     (12,788 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $4,155, $3,964 and $1,868, respectively
    6,469       6,324       3,429  
 
Total other comprehensive income (loss)
    6,633       5,404       (9,359 )
 
Comprehensive Income
  $ 121,424     $ 116,912     $ 145,790  
 
 
The accompanying notes are an integral part of these financial statements.
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NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2005 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 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). 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 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. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.
     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is 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 subsidiaries, Southern Company — Florida LLC (SCF), Oleander Power Project LP (Oleander) and Southern Power Company — Orlando Gasification LLC (SPC-OG), which were established to own, operate, and maintain the Company’s ownership interests in Plant Stanton Unit A, Oleander, and the integrated gasification combined cycle (IGCC) plant, respectively. See Note 2 under “Oleander Acquisition” and 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 $51.9 million in 2005, $46.7 million in 2004, and $47.5 million in 2003. Approximately $47.8 million in 2005, $40.3 million in 2004, and $32.8 million in 2003, were general, administrative, operation and maintenance expenses; the remainder was capitalized to construction work in progress. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA and management believes they are reasonable.
     The Company has agreements with Georgia Power and Alabama Power to provide operations 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

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
income. For the periods ended December 31, 2005, 2004, and 2003, these services totaled approximately $7.1 million, $6.6 million, and $6.1 million, respectively.
     Total billings for all purchased power agreements (PPAs) in effect with affiliates totaled $531 million, $383.0 million, and $282.2 million in 2005, 2004 and 2003 respectively. Included in these billings were $37.5 million, $39.1 million, and $28.4 million of affiliated deferred capacity revenues recorded on the balance sheets at December 31, 2005, December 31, 2004, and December 31, 2003, respectively.
     The Company and the retail operating companies 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 the retail operating company 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.
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, 2005, Georgia Power accounted for 53.6 percent of revenues, while Alabama Power and Savannah Electric were 8.2 percent and 6.5 percent of revenues, respectively. For the year ended December 31, 2004, Georgia Power accounted for 40.3 percent of revenues, with Alabama Power and Savannah Electric accounting for 8.4 percent and 4.5 percent of revenues, respectively. For the year ended December 31, 2003, Georgia Power accounted for approximately 33.7 percent of revenues, excluding $80 million related to termination of contracts with Dynegy, Inc. (Dynegy), with Alabama Power and Savannah Electric accounting for 5.5 percent and 5.0 percent, 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.
Property, Plant, and Equipment
The Company’s property, plant, and equipment consist entirely of generation assets.
     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. 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.
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 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 were recorded in 2003. There were no credits recorded in 2004 or 2005.
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 and Plant Oleander which have an estimated useful life of 40 years. These lives reflect a composite of the significant components (called retirement units) that make up the plants. Depreciation studies are conducted periodically to update the composite

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
rates. 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
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.
     At December 31, 2005, the Company had no liability for asset retirement obligations. In connection with the adoption of Financial Accounting Standards Board Statement No. 143, Accounting 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), representing removal costs for long-lived assets that the Company did not have a legal obligation to retire.
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 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 $3.8 million at December 31, 2005 and $3.2 million at December 31, 2004.
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.
Fuel Inventory
Fuel inventory includes the average cost of oil and emission allowances. The Company maintains minimal oil levels for use at Plant Dahlberg and Plant Oleander. Inventory is maintained using the weighted average cost method. Fuel and emissions are charged to inventory when purchased and then expensed as used.
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

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report
until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.
     The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.
     The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:
                 
    Carrying   Fair
    Amount   Value
    (in millions)
Long-term debt:
               
2005
  $ 1,100     $ 1,117  
2004
  $ 1,099     $ 1,114  
 
     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 such as opacity or other air quality standards, 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 potential litigation against the Company cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising would have a material adverse effect on the Company’s financial statements.
FERC Matters
Market-Based Rate Authority
The Company has authorization from the FERC to sell power to non-affiliates at market-based prices and 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 December 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 an issue. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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.
     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded

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investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Intercompany Interchange Contract
The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the propriety of the continued inclusion of the Company as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between the Company, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, will be subject to refund to the extent the FERC orders any changes to the IIC.
     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.
Oleander Acquisition
On June 7, 2005, the Company acquired all of the outstanding general and limited partnership interests of Oleander from subsidiaries of Constellation Energy Group, Inc. The results of Oleander’s operations have been included in the financial statements since that date. The Company’s acquisition of the general and limited partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate purchase price of approximately $206 million, plus approximately $12 million of working capital and other adjustments. Plant Oleander is a dual-fueled generating plant in Brevard County, Florida with a nameplate capacity of 628 megawatts (MW). The entire output of Plant Oleander is sold under separate PPAs with Florida Power & Light Company (FPL) and Seminole Electric Cooperative, Inc. (Seminole). The PPA with FPL is for one unit and extends through the end of May 2007. The Seminole PPA is for the remaining three units at Oleander and extends through the end of 2009. In February 2006, FPL extended its PPA for approximately 160 MW through 2012 and Seminole signed a new PPA for approximately 320 MW of capacity through 2015.
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, 2005, the Company’s investment in Unit 3 of Plant Franklin was $171.5 million. The final outcome of this matter cannot now be determined.

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Southern Power Company and Subsidiary Companies 2005 Annual Report
3. JOINT OWNERSHIP AGREEMENTS
The Company is a 65 percent owner of Plant Stanton A, a combined-cycle project with 630 MWs. The unit is co-owned by the Orlando Utilities Commission (OUC) (28 percent), Florida Municipal Power Agency (3.5 percent), and Kissimmee Utility Authority (3.5 percent). The Company has a service agreement with SCS whereby SCS is responsible for the operations and maintenance of Plant Stanton A. As of December 31, 2005, $155.7 million was recorded in plant in service with associated accumulated depreciation of $10 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 will be a 65 percent owner of the gasifier island portion of the new IGCC project at OUC’s Stanton Energy Center site. OUC will own the remaining 35 percent of the gasifier and 100 percent of the combined cycle portion of the IGCC project. The Company will construct the project for OUC at a fixed price. OUC will purchase the Company’s 65 percent capacity in the gasification island for 20 years after the date of commercial operation. In addition, the Company will manage the operations of the project after construction is completed using a joint staff of OUC and SCS employees.
     A cooperative agreement with DOE was signed in February 2006, which provides for up to $235 million in funding from the DOE to be applied by the joint owners for the construction and demonstration of the gasification portion of the project. The DOE will provide the funding in four phases throughout the development and demonstration of the gasifier. The Company’s share of the total cost related to the gasifier portion of the project is currently estimated at approximately $121 million. The IGCC project, subject to National Environmental Policy Act review and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in 2010.
4. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined tax returns for the State of Georgia, the State of Alabama and the State of Mississippi. Under a joint consolidated income tax allocation agreement, 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:
                         
    2005   2004   2003
    (in thousands)
Total provision for income taxes:
                       
Federal:
                       
Current
  $ 40,468     $ 40,492     $ 64,044  
Deferred
    20,437       19,939       19,203  
 
 
    60,905       60,431       83,247  
 
State:
                       
Current
    7,310       8,933       10,426  
Deferred
    3,618       3,571       3,318  
State manufacturer’s tax credits
                (11,770 )
 
 
    10,928       12,504       1,974  
 
Total
  $ 71,833     $ 72,935     $ 85,221  
 
     The tax effects of temporary differences between the carrying amounts of assets and liabilities within the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
                 
    2005   2004
    (in thousands)
Deferred tax liabilities:
               
Accelerated depreciation
  $ (127,913 )   $ (101,840 )
Book/tax basis difference on asset transfer
    (4,861 )     (6,455 )
 
Total
    (132,774 )     (108,295 )
 
Deferred tax assets:
               
Book/tax basis differences on asset transfers
    11,878       13,333  
Other comprehensive loss on interest rate swaps
    31,727       35,988  
Levelized capacity revenues
    14,221       13,819  
Other
    6,413       4,942  
 
Total
    64,239       68,082  
 
Accumulated deferred income taxes in the balance sheets
  $ (68,535 )   $ (40,213 )
 
     Deferred tax liabilities are primarily the result of property related timing differences and derivative hedging instruments. The transfer of the Plant McIntosh

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Southern Power Company and Subsidiary Companies 2005 Annual Report
construction project to Georgia Power and Savannah Electric in 2004 resulted in a deferred gain for federal income tax purposes. Georgia Power and Savannah Electric are reimbursing the Company for the related tax liability balance of $6.3 million. Of this total, $1.9 million is included in the balance sheet in Affiliated Accounts Receivable and the remainder is included in Other Affiliated Deferred Debits.
     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 related tax asset of $12.2 million. Of this total, $1.4 million is included in the balance sheet in Affiliated Accounts Payable and the remainder is included in Other Affiliated Deferred Credits.
     A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:
                         
    2005   2004   2003
 
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    3.8       4.4       3.7  
State manufacturer’s tax credits, net of federal effect
                (3.2 )
Other
    (0.3 )     0.1        
 
Effective income tax rate
    38.5 %     39.5 %     35.5 %
 
5. FINANCING
Bank Credit Arrangements
The Company has a $400 million unsecured syndicated revolving credit facility (Facility) expiring in April 2010. The purpose of the Facility is to provide liquidity support to the Company’s commercial paper program and other general corporate purposes. At December 31, 2005, the Company had $399 million available under the Facility.
     The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/8 of 1 percent. For the period ended December 31, 2005, the Company incurred approximately $0.8 million in expense from commitment fees under the Facility. Under a previous credit facility, for the periods ended December 31, 2004 and 2003, the Company incurred expenses of $2.1 million and $2.1 million from commitment fees, respectively.
     The Facility contains a covenant that requires a maximum 65 percent debt to capitalization ratio, as defined in the Facility. The Facility also contains a cross default provision that would be triggered if the Company defaulted on other indebtedness above a specified threshold. As of December 31, 2005, the Company was in compliance with all such covenants.
Dividend Restriction
The Facility also contains certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company’s projected cash flows from fixed priced capacity PPAs (as defined in the agreement) are at least 80 percent of total projected cash flows for the next twelve months or the Company’s debt to capitalization ratio is no greater than 60 percent. At December 31, 2005, the Company was in compliance with these ratios and had no restrictions on its ability to pay dividends.
Commercial Paper
The Company has the ability to borrow under a commercial paper program. For the periods ended December 31, 2005 and 2004, the peak commercial paper balance outstanding was $184.7 million and $114.5 million, respectively. The average amount outstanding was $63 million and $49.6 million in 2005 and 2004, respectively. The average annual interest rate was 3.7 percent in 2005 and 1.14 percent in 2004. As of December 31, 2005, the commercial paper program had an outstanding balance of $110.7 million. There was no commercial paper outstanding on December 31, 2004.
Financial Instruments
The Company enters into energy related derivatives to hedge 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.

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Southern Power Company and Subsidiary Companies 2005 Annual Report
These swaps 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, 2005, the Company had no interest derivatives outstanding. The Company has deferred losses totaling $82.4 million in other comprehensive income that will be amortized to interest expense through 2013 over the life of the related senior notes. For the years 2005, 2004, and 2003, approximately $11.2 million, $10.4 million, and $5.5 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. During 2006, approximately $11.9 million of pre-tax losses are expected to be reclassified from other comprehensive income to interest expense.
     Fair value gains or losses for cash flow hedges are recorded in other comprehensive income and reclassified to fuel expense. There were no material amounts reclassified during any year presented. For the year 2006, the reclassifications from other comprehensive income to fuel expense are expected to be immaterial. There was no significant ineffectiveness recorded in earnings for any period presented. The Company has energy-related hedges in place through 2007. 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 32 years. For the years 2005, 2004, and 2003, approximately $0.3 million per year of pre-tax gains were reclassified from other comprehensive income to depreciation and amortization. For 2006, approximately $0.3 million of pre-tax gains are expected to be reclassified from other comprehensive income to depreciation and amortization.
6. COMMITMENTS
Construction Program
The Company currently estimates property additions to be $162.3 million, $265.2 million, and $221.0 million in 2006, 2007, and 2008, 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 provide 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 Plants Dahlberg and Oleander, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg and Oleander agreements are in effect through the first hot gas path inspections and last combustion inspections, respectively, 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 $1.1 billion 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.
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.

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Southern Power Company and Subsidiary Companies 2005 Annual Report
     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 the New York Mercantile Exchange future prices at December 31, 2005.
         
    Fuel
Year   Purchases
 
    (in thousands)
2006
  $ 20,928  
2007
    21,272  
2008
    20,766  
2009
    18,589  
2010
    27,110  
2011 and beyond
    300,057  
 
Total
  $ 408,722  
 
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 2005 and 2004 is as follows:
                         
    Operating   Operating    
Quarter Ended   Revenues   Income   Net Income
    (in thousands)
March 2005
  $ 152,821     $ 56,745     $ 23,073  
June 2005
    149,226       60,611       25,234  
September 2005
    265,611       84,555       39,227  
December 2005
    213,346       61,656       27,257  
 
                       
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  
     The Company’s business is influenced by seasonal weather conditions. The Company had approximately 4,775 MWs and 5,403 MWs of generating capacity in service through May and December 2005, respectively.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2001-2005
Southern Power Company and Subsidiary Companies 2005 Annual Report
                                         
    2005     2004     2003     2002     2001  
 
Operating Revenues (in thousands):
                                       
Sales for resale — non-affiliates
  $ 223,058     $ 266,463     $ 278,559     $ 114,919     $ 26,390  
Sales for resale — affiliates
    556,664       425,065       312,586       183,111     2,906  
 
Total revenues from sales of electricity
    779,722       691,528       591,145       298,030     29,296  
Other revenues
    1,282       9,783       90,635       738     5  
 
Total
  $ 781,004     $ 701,311     $ 681,780     $ 298,768     $ 29,301  
 
Net Income (in thousands)
  $ 114,791     $ 111,508     $ 155,149     $ 54,270     $ 8,207  
Cash Dividends on Common Stock (in thousands)
  $ 72,400     $ 207,000     $     $     $  
Return on Average Common Equity (percent)
    13.68       12.23       17.65       8.94     3.51  
Total Assets (in thousands)
  $ 2,302,976     $ 2,067,013     $ 2,409,285     $ 2,085,976     $ 822,857  
Gross Property Additions (in thousands)
  $ 241,103     $ 115,606     $ 344,362     $ 1,214,677     $ 765,511  
 
Capitalization (in thousands):
                                   
Common stock equity
  $ 866,343     $ 811,611     $ 1,011,476     $ 746,604     $ 466,993  
Long-term debt
    1,099,520       1,099,435       1,149,112       955,879     293,205  
 
Total (excluding amounts due within one year)
  $ 1,965,863     $ 1,911,046     $ 2,160,588     $ 1,702,483     $ 760,198  
 
Capitalization Ratios (percent):
                                     
Common stock equity
    44.1       42.5       46.8       43.9       61.4  
Long-term debt
    55.9       57.5       53.2       56.1       38.6  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Security Ratings:
                                     
Unsecured Long-Term Debt -
                                     
Moody’s
  Baa1   Baa1   Baa1   Baa1      
Standard and Poor’s
  BBB+   BBB+   BBB+   BBB+      
Fitch
  BBB+   BBB+   BBB+   BBB+      
 
Kilowatt-Hour Sales (in thousands):
                                     
Sales for resale — non-affiliates
    3,932,638       5,369,261       6,057,053       1,240,290       164,926  
Sales for resale — affiliates
    6,355,249       6,583,017       5,430,973       3,607,107       69,307  
 
Total
    10,287,887       11,952,278       11,488,026       4,847,397       234,233  
 
Average Revenue Per Kilowatt-Hour (cents)
    7.58       5.79       5.15       6.15       12.51  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    5,403       4,775       4,775       2,408       800  
Maximum Peak-Hour Demand (megawatts):
                                     
Winter
    2,037       2,098       2,077       949        
Summer
    2,420       2,740       2,439       1,426        
Annual Load Factor (percent)
    48.9       54.4       54.9       51.1        
Plant Availability (percent)
    97.6       97.9       96.8       95.1       83.7  
Source of Energy Supply (percent):
                                     
Gas
    72.6       61.9       53.4       77.4       100.0  
Purchased power -
                                     
From non-affiliates
    9.6       24.7       30.5       5.9        
From affiliates
    17.8       13.4       16.1       16.7        
 
Total
    100.0       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 2006 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. The ages of Directors and Executive Officers set forth below are as of December 31, 2005.
     Additionally, Items 10, 11, 12, 13 and 14 for Alabama Power and Mississippi Power are incorporated by reference to the Information Statements of Alabama Power and Mississippi Power relating to each of their respective 2006 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 REGISTRANTS
GEORGIA POWER
Identification of directors of Georgia Power.
Michael D. Garrett
President, Chief Executive Officer and Director
Age 56
Served as Director since 2004
Gus H. Bell, III (1)
Age 68
Nominee
Robert L. Brown, Jr. (2)
Age 54
Served as Director since 2003
Ronald D. Brown (2)
Age 52
Served as Director since 2004
Anna R. Cablik (2)
Age 53
Served as Director since 2001
David M. Ratcliffe (2)
Age 57
Served as Director since 1999
D. Gary Thompson (2)
Age 59
Served as Director since 2003
Richard W. Ussery (2)
Age 58
Served as Director since 2001
William J. Vereen (2)
Age 65
Served as Director since 1988
E. Jenner Wood, III (2)
Age 54
Served as Director since 2001
(1) Mr. Bell is a nominee to Georgia Power’s Board of Directors to be elected at the 2006 annual meeting of Georgia Power shareholders. (2) No position other than director.
     Each of the above (other than Mr. Bell) is currently a director of Georgia Power, serving a term running from the last annual meeting of Georgia Power’s shareholders (May 18, 2005) for one year until the next annual meeting or until a successor is elected and qualified.
     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of Georgia Power acting solely in their capacities as such.

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Identification of executive officers of Georgia Power.
Michael D. Garrett
President, Chief Executive Officer and Director
Age 56
Served as Executive Officer since 2003
William C. Archer, III (1)
Executive Vice President
Age 57
Served as Executive Officer since 1995
Mickey A. Brown
Executive Vice President
Age 58
Served as Executive Officer since 2001
Cliff S. Thrasher
Executive Vice President, Chief Financial Officer and Treasurer
Age 55
Served as Executive Officer since 2005
Christopher C. Womack (2)
Executive Vice President
Age 47
Served as Executive Officer since 2001
Judy M. Anderson
Senior Vice President
Age 57
Served as Executive Officer since 2001
Richard L. Holmes
Senior Vice President
Age 54
Served as Executive Officer since 2003
Douglas E. Jones (3)
Senior Vice President
Age 47
Served as Executive Officer since 2005
James H. Miller, III
Senior Vice President and General Counsel
Age 56
Served as Executive Officer since 2004
Leslie R. Sibert
Vice President
Age 43
Served as Executive Officer since 2001

Gene L. Ussery, Jr.
Vice President
Age 56
Served as Vice President since 2005
(1)   Mr. Archer will retire as Executive Vice President, effective March 19, 2006.
 
(2)   Mr. Womack was elected Executive Vice President of External Affairs, effective March 11, 2006.
 
(3)   Mr. Jones was elected Senior Vice President of Fossil and Hydro Generation, effective March 11, 2006.
     Each of the above is currently an executive officer of Georgia Power, serving a term running from the last annual organizational meeting of the directors (May 18, 2005) for one year until the next annual meeting or until their successors are elected and qualified, except for Messrs. Jones and Womack whose elections will be effective on March 11, 2006.
     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Georgia Power acting solely in their capacity as such.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Unless noted otherwise, each director has served in his or her present position for at least the past five years.
Michael D. Garrett - President and Chief Executive Officer of Georgia Power since April 2004. He previously served as President of Georgia Power from January 2004 to April 2004; President and Chief Executive Officer and Director of Mississippi Power from May 2001 to December 2003, and Executive Vice President — Customer Service of Alabama Power from January 2000 to May 2001.

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Gus H. Bell, III — Chairman of the Board, 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 1986. Advisory Director of SunTrust Bank of Savannah. Mr. Bell also serves as a director of Savannah Electric.
Robert L. Brown, Jr. — President and Chief Executive Officer of R.L. Brown & Associates Inc. (architectural/construction management company), Decatur, Georgia. He is a Director of Citizens Trust Bank.
Ronald D. Brown — President and Chief Executive Officer of Atlanta Life Financial Group (financial services company), Atlanta, Georgia. He previously served as Chief Executive Officer and Managing Partner of the Variant Group LLC, Atlanta, Georgia, from 2001 to 2004 and Chief Executive Officer of SYNAVANT Inc., Atlanta, Georgia, from 2000 to 2001.
Anna R. Cablik — President of Anatek, Inc. , Marietta, Georgia, and Anasteel & Supply Company, LLC, Ellenwood, Georgia (suppliers of fabricated concrete reinforcing steel); President of MassAna Construction (general construction), Marietta, Georgia; and a partner of PanAmerican Logistics, PanAmerican International and Atlanta International Foods, Atlanta, Georgia. She is a Director of Branch Banking and Trust Company.
David M. Ratcliffe — Chairman of the Board, President and Chief Executive Officer of Southern Company since July 2004. He previously served as President of Southern Company from April 2004 until July 2004; Executive Vice President of Southern Company from May 1999 until April 2004; President and Chief Executive Officer of Georgia Power from May 1999 to January 2004 and Chairman and Chief Executive Officer of Georgia Power from January 2004 to April 2004. He is a Director of CSX Corporation, Alabama Power and Southern Power.
D. Gary Thompson — Retired, Chief Executive Officer of Georgia Banking, Wachovia Bank, N.A., Atlanta, Georgia, and Executive Vice President of Wachovia Corporation, Charlotte, North Carolina, from June 1995 until December 2004. He is a Director of American Family Life Assurance Company of Columbus (AFLAC).
Richard W. Ussery — Retired, Chairman of the Board of Total Systems Services (TSYS) (credit card processing facility), Columbus, Georgia, from January 2004 until January 2006. He previously served as Chairman of the Board and Chief Executive Officer of TSYS from 1992 to 2004. He is a Director of TSYS.
William J. Vereen — Chairman, President and Chief Executive Officer of Riverside Manufacturing Company (manufacturer and sales of uniforms), Moultrie, Georgia. He is a Director of Gerber Scientific, Inc.
E. Jenner Wood, III — Chairman, President and Chief Executive Officer of SunTrust Bank, Central Group and Executive Vice President of SunTrust Banks Inc., Atlanta, Georgia. He previously served as President of SunTrust Bank, Atlanta and SunTrust Bank Georgia from 2000 to 2001. He is a Director of Oxford Industries, Inc. and Crawford & Company.
William C. Archer, III — Executive Vice President of External Affairs since 1995 and will retire effective March 19, 2006.
Mickey A. Brown — Executive Vice President of the Customer Service Organization since January 2005. He previously served as Senior Vice President of Distribution from 2001 to 2005; and Vice President, Distribution from 2000 to 2001.
Cliff S. Thrasher — Executive Vice President, Chief Financial Officer and Treasurer since March 2005. He previously served as Senior Vice President, Comptroller and Chief Financial Officer of Southern Power from November 2002 to March 2005 and Vice President of SCS from June 2002 to March 2005; and Vice President, Comptroller and Chief Accounting Officer of Georgia Power from September 1995 to June 2002.
Christopher C. Womack — Executive Vice President of External Affairs, effective March 11, 2006. He currently serves as Senior Vice President of Fossil and Hydro Generation and Senior Production Officer since 2001. He previously served as Senior Vice President of Human Resources of SCS from 1998 to 2001.

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Judy M. Anderson — Senior Vice President of Charitable Giving since 2001. She previously served as Vice President and Corporate Secretary of Georgia Power from 1989 to 2001.
Richard L. Holmes — Senior Vice President of Metro Atlanta Region, since January 2006. He served as Senior Vice President of Metro Atlanta Region, Diversity and Corporate Relations from 2005 to 2006. He previously served as Senior Vice President of Corporate Services from 2003 to 2005; Vice President of Administrative Services from 2002 to 2003; and Vice President of Region Operations from 2000 to 2002.
Douglas E. Jones — Senior Vice President of Fossil and Hydro Generation, effective March 11, 2006. He currently serves as Senior Vice President of Customer Service and Sales since January 2005. He 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.
James H. Miller, III — Senior Vice President and General Counsel since March 2004. He 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. He is a Director of Fidelity Southern Corporation.
Leslie R. Sibert — Vice President, Transmission since 2001. She previously served as Decatur Region Manager from 1999 to 2001.
Gene L. Ussery, Jr. — Vice President, Distribution since February 2005. He previously served as Vice President and Senior Production Officer of Mississippi Power and Gulf Power from 2002 to 2005 and Vice President, Power Generation and Delivery, Mississippi Power from 2000 to 2002.
Involvement in certain legal proceedings.
None.
Section 16(a) Beneficial Ownership Reporting
Compliance.

None.
GULF POWER
Identification of directors of Gulf Power.
Susan N. Story
President and Chief Executive Officer
Age 45
Served as Director since 2003
C. LeDon Anchors (1)
Age 65
Served as Director since 2001
William C. Cramer, Jr. (1)
Age 53
Served as Director since 2002
Fred C. Donovan, Sr. (1)
Age 65
Served as Director since 1991
William A. Pullum (1)
Age 58
Served as Director since 2001
Winston E. Scott (1)
Age 55
Served as Director since 2003
(1)   No position other than director.
     Each of the above is currently a director of Gulf Power, serving a term running from the last annual meeting of Gulf Power’s shareholders (May 18, 2005) for one year until the next annual meeting or until a successor is elected and qualified.
     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.
Identification of executive officers of Gulf Power.
Susan N. Story
President and Chief Executive Officer
Age 45
Served as Executive Officer since 2003

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Francis M. Fisher, Jr.
Vice President – Customer Operations
Age 57
Served as Executive Officer since 1989
P. Bernard Jacob
Vice President – External Affairs and
Corporate Services
Age 51
Served as Executive Officer since 2003
Ronnie R. Labrato
Vice President and Chief Financial Officer
Age 52
Served as Executive Officer since 2000
Penny M. Manuel
Vice President – Senior Production Officer
Age 43
Served as Executive Officer since 2005
     Each of the above is currently an executive officer of Gulf Power, serving a term running from the last annual organizational meeting of the directors (July 28, 2005) for one year until the next annual meeting or until a successor is elected and qualified.
     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Unless noted otherwise, each director has served in his or her present position for at least the past five years.
Susan N. Story – President and Chief Executive Officer since 2003. She previously served as Executive Vice President of SCS from January 2001 to April 2003; Senior Vice President of Southern Power from November 2002 to April 2003; Vice President of SCS from May 2000 to January 2001.
C. LeDon Anchors - Attorney and President of Anchors Smith Grimsley, Attorneys at Law, Fort Walton Beach, Florida. He is Chairman of Regions Bank of Okaloosa County.
William C. Cramer, Jr. — President and Owner of Tommy Thomas Chevrolet, Panama City, Florida.
Fred C. Donovan, Sr. — Chairman and Chief Executive Officer of Baskerville-Donovan, Inc. (an architectural and engineering firm), Pensacola, Florida.
William A. Pullum - Broker/President of Bill Pullum Realty, Inc., Navarre, Florida, and Owner, President and Director of Cowboy’s Steakhouse, Navarre, Florida.
Winston E. Scott - Executive Director of the Florida Space Authority, Cape Canaveral, Florida. He previously served as a professor and associate dean with the Florida Agriculture and Mechanical University and Florida State University (FSU) College of Engineering in 2003, Vice President for Student Affairs at FSU from 2000 until 2003 and Associate Vice President with the Division of Student Affairs at FSU from 1999 to 2000.
Francis M. Fisher, Jr.
Vice President of Customer Operations since 1996.
P. Bernard Jacob — Vice President of External Affairs and Corporate Services since 2003. He 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 and Chief Financial Officer since January 14, 2006. He previously served as Vice President, Chief Financial Officer and Comptroller from 2001 to 2006.
Penny M. Manuel — Vice President and Senior Production Officer since February 2005. She 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.

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Involvement in certain legal proceedings.
None.
Section 16(a) Beneficial Ownership Reporting Compliance.
None.
SAVANNAH ELECTRIC
Identification of directors of Savannah Electric.
W. Craig Barrs
Age 48
Served as Director since 2005
Gus H. Bell, III (1)
Age 68
Served as Director since 1999
Archie H. Davis (1)
Age 64
Served as Director since 1997
Robert B. Miller, III (1)
Age 60
Served as Director since 1983
Arnold M. Tenenbaum (1)
Age 69
Served as Director since 1977
(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 (April 29, 2005) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Barrs who was elected on December 13, 2005.
     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.
W. Craig Barrs (1)
President, Chief Executive Officer and Director
Age 48
Served as Executive Officer since 2005
W. Miles Greer
Vice President
Age 62
Served as Executive Officer since 1985
Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 54
Served as Executive Officer since 1994
     Each of the above is currently an executive officer of Savannah Electric, serving a term running from the last annual organizational meeting of the directors (August 4, 2005) for one year, except for Mr. Barrs whose election was on December 13, 2005.
(1)   Mr. Barrs was elected President and Chief Executive Officer, effective December 13, 2005. He will be named Vice President of Georgia Power’s new coastal region when the merger of Georgia Power and Savannah Electric is completed.
     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.
W. Craig Barrs
President and Chief Executive Officer since December 2005. He previously served as Vice President of Community and Economic

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Development for Georgia Power from November 2002 to December 2005; Assistant to the President of Georgia Power from June 2002 to November 2003; and Regulatory Affairs Manager of Georgia Power from March 1999 to June 2002.
Gus H. Bell, III — Chairman of the Board, 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 1986. 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. He 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.
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. He 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. He is Chairman of the Board of Directors of FCB Financial Corp., 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.
None.
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
Georgia Power Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the five most highly compensated executive officers serving during 2005.
                                                         
    ANNUAL COMPENSATION   LONG-TERM COMPENSATION
                                    Number of        
                                    Securities        
                                    Underlying   Long-Term    
                            Other Annual   Stock   Incentive   All Other
Name and                           Compensation   Options   Payouts   Compensation
Principal Position   Year   Salary($)   Bonus($)   ($)1   (Shares)   ($)2   ($)3
 
Michael D. Garrett
President, Chief
    2005       526,125       850,669       6,275       78,565       139,687       27,974  
Executive Officer,
    2004       498,323       764,213       161,355       53,419       231,474       121,563  
Director
                                                       
 
                                                       
James H. Miller, III
    2005       298,553       319,785       21,182       27,073       129,989       41,456  
Senior Vice President,
    2004       291,698       294,772       79,597       27,361       192,587       14,546  
General Counsel
                                                       
 
                                                       
William C. Archer
    2005       293,106       313,951       47,061       26,579       137,031       91,126  
Executive Vice
    2004       276,867       291,928       3,716       25,582       168,992       14,412  
President
    2003       262,894       267,282       3,142       26,560       234,317       14,029  
 
                                                       
Christopher C. Womack
    2005       290,472       288,552       57,373       26,413       135,237       31,049  
Executive Vice
    2004       278,010       250,897       8,530       26,310       218,962       27,630  
President
    2003       266,274       246,799       11,074       26,923       247,563       23,648  
 
                                                       
Mickey A. Brown
    2005       286,403       308,874       2,680       26,199       69,032       15,155  
Executive Vice
    2004       243,714       224,990       3,227       18,820       119,742       13,117  
President
    2003       226,601       216,296       2,492       18,091       141,113       11,080  
 
                                                       
C. B. Harreld4
Executive Vice
    2005       286,867       302,383       18,777       25,498       57,204       37,738  
President, Chief
    2004       263,053       277,362       5,156       24,306       87,902       13,902  
Financial Officer
    2003       240,504       231,977       10,153       19,117       111,832       28,027  
 
1   This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column. In 2005, the amount for Mr. Womack includes country club dues of $25,669. In 2004, the amount for Messrs. Garrett and Miller also includes country club dues of $60,000 and $37,500, respectively.
 
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, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five 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 above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
 
3   Contributions in 2005 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) are as follows:
                         
Name   ESP   ESOP   SBP
             
Michael D. Garrett
  $ 9,450     $ 773     $ 17,751  
James H. Miller, III
    9,450       773       6,233  
William C. Archer
    8,769       773       6,584  
Christopher C. Womack
    9,450       773       5,826  
Mickey A. Brown
    9,450       773       4,932  
C. B. Harreld
    9,169       773       1,796  
 
    In 2005, Messrs. Miller, Archer, Womack and Harreld received additional incentive compensation of $25,000, $75,000, $15,000 and $26,000, respectively. In 2004, Messrs. Garrett and Womack received additional incentive compensation in the amounts of $25,000 and $12,500, respectively. In 2004, Mr. Garrett received additional relocation assistance of $71,698. In 2003, Messrs. Womack and Harreld received additional incentive compensation of $10,000 and $15,554, respectively.
 
4   Mr. Harreld resigned from Georgia Power effective March 17, 2005 and was elected Executive Vice President of SCS and Chief Financial Officer of Southern Company’s transmission business unit.

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Gulf Power Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the five most highly compensated executive officers serving during 2005.
                                                         
    ANNUAL COMPENSATION   LONG-TERM COMPENSATION
                                    Number of        
                                    Securities   Long-    
Name                                   Underlying   Term    
and                           Other Annual   Stock   Incentive   All Other
Principal                           Compensation   Options   Payouts   Compensation
Position   Year   Salary($)   Bonus($)   ($)5   (Shares)   ($)6   ($)7
 
Susan N. Story
President, Chief
    2005       332,029       348,515       3,651       38,529       75,816       17,571  
Executive Officer,
    2004       313,256       254,668       6,811       37,837       156,306       16,531  
Director
    2003       297,771       245,241       3,572       24,978       138,695       14,203  
 
                                                       
Francis M. Fisher, Jr.
    2005       230,294       180,481       2,597       17,102       75,503       11,603  
Vice President
    2004       222,455       135,067       3,470       17,200       104,933       13,987  
 
    2003       214,404       130,248       2,436       17,737       135,659       10,772  
 
                                                       
Ronnie R. Labrato
    2005       211,120       165,757       6,200       15,707       44,197       20,890  
Vice President and
    2004       202,063       122,861       2,399       15,646       47,631       12,986  
Chief Financial Officer
    2003       183,716       108,945       21       11,530       57,461       9,217  
 
                                                       
P. Bernard Jacob
    2005       190,869       149,993       8,439       14,213       21,441       24,711  
Vice President
    2004       180,415       109,874       3,093       14,090       25,664       12,112  
 
    2003       167,967       94,904       2,471       6,678       22,150       7,734  
 
                                                       
Penny M. Manuel8
    2005       163,737       128,128       5,524       5,961       20,159       25,196  
Vice President
                                                       
 
                                                       
Gene L. Ussery, Jr.9
    2005       252,160       243,312       6,553       18,944       61,442       18,290  
Vice President
    2004       230,587       187,621       10,534       17,886       87,520       27,759  
 
    2003       218,752       182,806       8,388       18,129       110,711       11,488  
 
5   This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column.
 
6   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, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five 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 above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
 
7   Contributions in 2005 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) are as follows:
                         
Name   ESP   ESOP   SBP
             
Susan N. Story
  $ 9,450     $ 773     $ 7,348  
Francis M. Fisher, Jr.
    8,703       773       2,127  
Ronnie R. Labrato
    9,408       773       709  
P. Bernard Jacob
    8,589       773       349  
Penny M. Manuel
    7,221       773       202  
Gene L. Ussery, Jr.
    9,450       773       3,067  
 
    In 2005, this amount for Messrs. Labrato, Jacob and Ussery includes additional incentive compensation of $10,000, $15,000 and $5,000, respectively, and for Ms. Manuel includes incentive compensation of $17,000 related to relocation. In 2004, the amounts for Messrs. Fisher, Labrato and Jacob included additional incentive compensation of $3,000, $3,000 and $3,000, respectively.
 
8   Ms. Manuel became an executive officer of Gulf Power in February 2005.
 
9   Mr. Ussery resigned from Gulf Power in February 2005 and was elected a Vice President of Georgia Power in February 2005.

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Savannah Electric Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the two most highly compensated executive officers serving during 2005.
                                                         
    ANNUAL COMPENSATION   LONG-TERM COMPENSATION
                                    Number of        
                                    Securities   Long-    
Name                                   Underlying   Term    
and                           Other Annual   Stock   Incentive   All Other
Principal                           Compensation   Options   Payouts   Compensation
Position   Year   Salary($)   Bonus($)   ($)10   (Shares)   ($)11   ($)12
 
Anthony R. James13
    2005       273,741       252,006       3,325       31,709       106,779       14,710  
Chairman
    2004       260,755       214,741       3,403       31,435       158,804       13,881  
 
    2003       248,342       183,462       3,168       32,015       164,732       11,956  
 
                                                       
W. Craig Barrs14
    2005       175,155       150,908       797       10,162       31,164       8,729  
President, Chief Executive Officer, Director
                                                       
 
                                                       
W. Miles Greer
    2005       209,882       128,342       166       12,111       42,640       25,613  
Vice President
    2004       203,900       111,487       57       12,240       87,556       23,507  
 
    2003       198,238       97,376       1,716       12,744       111,890       24,702  
 
                                                       
Kirby R. Willis
Vice President, Chief Financial Officer,
    2005       193,440       118,287       924       11,162       39,213       16,010  
Treasurer, Assistant
    2004       187,827       82,202       748       11,281       61,834       15,602  
Corporate Secretary
    2003       182,109       89,491       2,207       11,712       68,470       14,634  
 
10   This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column.
 
11   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, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five 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 above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
 
12   Contributions in 2005 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
  $ 9,216     $ 773     $ 4,621  
W. Craig Barrs
    7,362       773       494  
W. Miles Greer
    9,445       773       15,295  
Kirby R. Willis
    7,935       679       7,296  
 
    In 2005, this amount for Messrs. James, Greer and Willis includes a $100 safety award.
 
13   Mr. James resigned as President and Chief Executive Officer of Savannah Electric effective December 13, 2005 and was elected Chairman of Savannah Electric’s board of directors from December 13, 2005 until January 31, 2006. In addition, Mr. James was elected an Executive Vice President of SCS on December 13, 2005.
 
14   Mr. Barrs was elected President and Chief Executive Officer of Savannah Electric effective December 13, 2005.

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STOCK OPTION GRANTS IN 2005
The following table sets forth all stock option grants to the named executive officers during the year ending December 31, 2005.
                                         
    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 15   Fiscal Year 16   ($/Sh) 15   Date 15   Present Value17
 
Georgia Power
                                       
 
                                       
Michael D. Garrett
    78,565       5.6     $ 32.70       02/18/2015     $ 306,404  
James H. Miller, III
    27,073       1.9     $ 32.70       02/18/2015       105,585  
William C. Archer
    26,579       1.9     $ 32.70       02/18/2015       103,658  
Christopher C. Womack
    26,413       1.9     $ 32.70       02/18/2015       103,011  
Mickey A. Brown
    26,199       1.9     $ 32.70       02/18/2015       102,176  
C. B. Harreld
    25,498       1.8     $ 32.70       02/18/2015       99,442  
 
                                       
Gulf Power
                                       
 
                                       
Susan N. Story
    38,529       15.4     $ 32.70       02/18/2015       150,263  
Francis M. Fisher, Jr.
    17,102       6.8     $ 32.70       02/18/2015       66,698  
Ronnie R. Labrato
    15,707       6.3     $ 32.70       02/18/2015       61,257  
P. Bernard Jacob
    14,213       5.7     $ 32.70       02/18/2015       55,431  
Penny M. Manuel
    5,961       2.4     $ 32.70       02/18/2015       23,248  
Gene L. Ussery, Jr.
    18,944       7.5     $ 32.70       02/18/2015       73,882  
 
                                       
Savannah Electric
                                       
 
                                       
Anthony R. James
    31,709       26.2     $ 32.70       02/18/2015       123,665  
W. Craig Barrs
    10,162       8.4     $ 32.70       02/18/2015       39,632  
W. Miles Greer
    12,111       10.0     $ 32.70       02/18/2015       47,233  
Kirby R. Willis
    11,162       9.2     $ 32.70       02/18/2015       43,532  
 
15   Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 18, 2005 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.
 
16   A total of 1,411,442, 250,874 and 120,986 stock options were granted in 2005 to the employees of Georgia Power, Gulf Power and Savannah Electric, respectively.
 
17   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
 
17.9%   3.87%   4.38%   5 years
 

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AGGREGATED STOCK OPTION EXERCISES IN 2005 AND YEAR-END OPTION VALUES
The following table sets forth information concerning options exercised during the year ending December 31, 2005 by the named executive officers and the value of unexercised options held by them as of December 31, 2005.
                                                 
    Shares           Number of Securities Underlying   Value of Unexercised
    Acquired           Unexercised Options at Fiscal   In-the-Money Options
    on   Value   Year-End (#)   At Year-End ($)18
Name   Exercise (#)   Realized ($)19   Exercisable   Unexercisable   Exercisable   Unexercisable
 
Georgia Power
                                               
 
                                               
Michael D. Garrett
    100,000       1,013,825       38,885       129,413       227,735       422,774  
James H. Miller, III
    28,318       395,271       101,644       54,969       966,236       204,586  
William C. Archer
    0       0       112,611       52,486       1,206,509       192,453  
Christopher C. Womack
    42,954       821,660       110,009       52,927       1,169,434       195,387  
Mickey A. Brown
    41,177       495,869       38,396       44,775       296,584       150,577  
C. B. Harreld
    28,628       249,479       20,847       48,074       124,296       169,936  
 
                                               
Gulf Power
                                               
 
                                               
Susan N. Story
    75,305       858,273       19,265       72,079       107,047       251,962  
Francis M. Fisher, Jr.
    12,146       178,541       56,487       34,480       521,513       127,724  
Ronnie R. Labrato
    1,500       14,758       23,269       29,980       172,718       106,398  
P. Bernard Jacob
    9,417       75,180       0       25,832       0       87,848  
Penny M. Manuel
    0       0       12,380       11,908       95,509       43,883  
Gene L. Ussery, Jr.
    16,656       185,802       37,115       36,911       285,964       134,257  
 
                                               
Savannah Electric
                                               
 
                                               
Anthony R. James
    33,227       462,548       65,312       63,337       503,065       233,391  
W. Craig Barrs
    11,619       158,890       17,312       20,235       127,802       74,479  
W. Miles Greer
    32,505       447,151       26,854       24,519       208,571       91,054  
Kirby R. Willis
    14,601       184,301       24,659       22,586       191,444       83,843  
 
18   This column represents the excess of the fair market value of Southern Company’s common stock of $34.53 per share, as of December 31, 2005, 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, 2005.
 
19   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 Georgia Power, Gulf Power and 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 Tables on pages III-8 through III-10.
                                                     
        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  
  1,500,000       382,500       510,000       637,500       765,000       892,500       1,020,000  
     As of December 31, 2005, the applicable compensation levels and years of accredited service for Georgia Power’s, Gulf Power’s and Savannah Electric’s executive officers are presented in the following tables:
Georgia Power
                 
    Compensation   Accredited
Name   Level   Years of Service
Michael D. Garrett
  $ 1,071,895       37  
James H. Miller, III20
    550,038       21  
William C. Archer
    530,649       34  
Christopher C. Womack21
    500,519       25  
Mickey A. Brown
    469,242       35  
C. B. Harreld 22
    501,389       32  
 
20   The number of accredited years of service includes 10 years credited to Mr. Miller pursuant to a supplemental pension agreement.
 
21   The number of accredited years of service includes eight years credited to Mr. Womack pursuant to a supplemental pension agreement.
 
22   The number of accredited years of service includes 10 years credited to Mr. Harreld pursuant to a deferred compensation agreement.

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Table of Contents

Gulf Power
                 
    Compensation   Accredited
Name   Level   Years of Service
Susan N. Story
  $ 548,779       23  
Francis M. Fisher, Jr.
    338,949       34  
Ronnie R. Labrato
    305,820       26  
P. Bernard Jacob
    270,464       22  
Penny M. Manuel
    224,814       22  
Gene L. Ussery, Jr.
    405,889       37  
Savannah Electric
                 
    Compensation   Accredited
Name   Level   Years of Service
Anthony R. James
  $ 440,603       26  
W. Craig Barrs
    285,876       24  
W. Miles Greer23
    286,813       29  
Kirby R. Willis24
    257,532       31  
     The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities or computation of Social Security offset that would apply in most cases.
     In 1998, Savannah Electric merged its pension plan into the Southern Company Pension Plan. Savannah Electric also has in effect a supplemental executive retirement plan for certain of its executive employees. The plan is designed to provide participants with a supplemental retirement benefit, which, in conjunction with Social Security and benefits under Southern Company’s qualified pension plan, will equal 70 percent of the highest three of the final 10 years’ average annual earnings (excluding incentive compensation).
     The following table sets forth the estimated combined annual pension benefits under Southern Company’s pension and Savannah Electric’s supplemental executive retirement plans in effect during 2005 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  
 
23   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.
 
24   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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Compensation of Directors.
Standard Arrangements. The following fees are paid to the directors of the respective company 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 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.
     
Georgia Power
   
 
   
Annual Cash Retainer Fee
  $22,000
Committee Chair Annual Retainer
  $3,000
Annual Stock Retainer Fee
  520 shares of Southern Company common stock
Meeting Fees
  $1,800 for each Board meeting attended,
 
  $1,200 for each Committee meeting attended and
 
  $1,200 for each site visit, extra session or conference fee
 
   
Gulf Power
   
 
   
Annual Cash Retainer Fee
  $12,000
Quarterly Stock Retainer Fee
  85 shares of Southern Company common stock
Meeting Fees
  $1,200 for each Board meeting attended and
 
  $1,000 for each Committee meeting attended
Savannah Electric
   
 
   
Annual Cash Retainer Fee
  $12,000
Quarterly Stock Retainer Fee
  85 shares of Southern Company common stock
Meeting Fees
  $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, 2005 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.
Georgia Power, Gulf Power and Savannah Electric have adopted Southern Company’s Change in Control Program, which is applicable to its officers, and as part of the program, Georgia Power has entered into an individual change in control agreement with its president and chief executive officer and Savannah Electric with Mr. Anthony James, its former president and chief executive officer. If an officer is involuntarily terminated, other than for cause, within two years following a change in control of Southern Company, Georgia Power, Gulf Power and Savannah Electric, 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 in connection with an actual or threatened change in control,
 
  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 Georgia Power or Gulf Power or Savannah Electric is defined under the agreements as:
  acquisition of at least 50 percent of that Company’s stock,
 
  a merger or other business combination unless Southern Company controls the surviving entity or
 
  a sale of substantially all the assets of that Company.
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 a comparable plan or plans.
On May 31, 2002, Southern Company, SCS and Mr. Christopher Womack entered into a Deferred Compensation Agreement which, upon Mr. Womack’s termination, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and Supplemental Executive Retirement Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional eight years. This agreement also contains customary releases and an agreement by Mr. Womack to not engage in specified competitive activities for two years following his retirement.
On May 12, 2003, SCS, Southern Nuclear, Alabama Power and Mr. James Miller entered into an Amended and Restated Supplemental Pension Agreement which, upon Mr. Miller’s termination, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional 10 years.
On September 17, 2003, Georgia Power, SCS, Southern Company and Mr. C. B. Harreld entered into an Amended and Restated Supplemental Pension Agreement which, upon Mr. Harreld’s retirement, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional 10 years.

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On January 4, 2006, Georgia Power entered into a separation agreement (the “Separation Agreement”) with William C. Archer, III, an Executive Vice President of the Company, concurrent with his retirement from the Company. Upon Mr. Archer’s termination of employment effective as of March 19, 2006 (the “Separation Date”) and his execution of a release agreement in the form attached to the Separation Agreement (the “Release”), Mr. Archer will be entitled to receive a lump sum payment of $789,400 as soon as practicable following the Separation Date. In the event of a change in control of Georgia Power or Southern Company, Mr. Archer will be entitled to receive the lump sum termination payment under the Separation Agreement as soon as practicable following the change in control.
     In addition, following his retirement, Mr. Archer has agreed to provide certain consulting services to Georgia Power as an independent contractor in accordance with the terms of a consulting agreement (the “Consulting Agreement”). Under the Consulting Agreement, which was executed on January 4, 2006, Mr. Archer will provide professional consulting services as may be requested by Georgia Power and will receive an annual retainer fee of $200,000 to provide such services. In addition, Mr. Archer will be entitled to (i) payment of executive financial planning fees of $6,000 per year during the term of the Consulting Agreement, (ii) reimbursement of reasonable expenses incurred in providing consulting services up to $5,000 per year, and (iii) reimbursement of athletic club membership fees during the term of the Consulting Agreement. The Consulting Agreement will expire March 19, 2009, unless earlier terminated in accordance with its terms. The Consulting Agreement includes confidentiality, non-disclosure and non-interference provisions that apply during the term of the Consulting Agreement and for periods of time following its termination.
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
Security Ownership of Certain Beneficial Owners. Southern Company is the beneficial owner of 100% of the outstanding common stock of Georgia Power, Gulf Power and 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
            100 %
       
30 Ivan Allen Jr. Boulevard, N.W.
               
       
Atlanta, Georgia 30308
               
       
 
               
       
Registrants:
               
       
Georgia Power
    7,761,500          
       
Gulf Power
    992,717          
       
Savannah Electric
    10,844,635          
Security Ownership of Management. The following tables show the number of shares of Southern Company common stock owned by the directors, nominees and executive officers as of December 31, 2005. 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, 2005.
                         
                    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)
 
Georgia Power
                       
 
                       
Michael D. Garrett
  Southern Company Common     99,585       98,116  
Gus H. Bell, III
  Southern Company Common     1,409          
Robert L. Brown
  Southern Company Common     4,290          
Ronald D. Brown
  Southern Company Common     470          
Anna R. Cablik
  Southern Company Common     2,874          
David M. Ratcliffe
  Southern Company Common     611,615       596,499  
D. Gary Thompson
  Southern Company Common     12,992          
Richard Ussery
  Southern Company Common     28,798          
William J. Vereen
  Southern Company Common     9,011          
E. Jenner Wood, III
  Southern Company Common     4,476          
William C. Archer
  Southern Company Common     140,259       138,851  
Mickey A. Brown
  Southern Company Common     72,746       59,432  
James H. Miller, III
  Southern Company Common     134,410       129,445  
Christopher C. Womack
  Southern Company Common     137,788       136,558  
 
                       
Directors, Nominees and Executive Officers as a group (20 people)
  Southern Company Common     1,580,936       1,449,963  

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                    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)
 
Gulf Power
                       
 
                       
Susan N. Story
  Southern Company Common     57,924       53,046  
C. LeDon Anchors
  Southern Company Common     3,645          
William C. Cramer, Jr.
  Southern Company Common     3,877          
Fred C. Donovan, Sr.
  Southern Company Common     2,140          
William A. Pullman
  Southern Company Common     4,886          
Winston E. Scott
  Southern Company Common     1,810          
Francis M. Fisher, Jr.
  Southern Company Common     77,126       73,833  
P. Bernard Jacob
  Southern Company Common     14,646       11,660  
Ronnie R. Labrato
  Southern Company Common     41,008       37,563  
Penny M. Manuel
  Southern Company Common     19,157       18,344  
 
                       
Directors, Nominees and Executive Officers as a group (10 people)
  Southern Company Common     226,219       194,446  
                         
                    Shares Beneficially
                    Owned Include:
               Name of Directors,           Shares   Shares Individuals
                   Nominees and           Beneficially   Have Rights to Acquire
               Executive Officers   Title of Class   Owned (1)   Within 60 days(2)
 
Savannah Electric
                       
 
                       
W. Craig Barrs
  Southern Company Common     33,252       27,446  
Gus H. Bell, III
  Southern Company Common     1,409          
Archie H. Davis
  Southern Company Common     1,878          
Robert B. Miller, III
  Southern Company Common     3,310          
Arnold M. Tenenbaum
  Southern Company Common     2,429          
W. Miles Greer
  Southern Company Common     45,953       39,219  
Kirby R. Willis
  Southern Company Common     41,835       36,044  
                         
Directors, Nominees and Executive Officers as a group (7 people)
  Southern Company Common     130,066       102,709  
 
(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). For Robert B. Miller, III, this amount includes 1,850 shares held jointly with the estate of Robert B. Miller Jr. and Jean Miller.
 
(2)   Indicates shares of Southern Company common stock that directors and executive officers have the right to acquire within 60 days.

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Changes in control. Southern Company, Georgia Power, Gulf Power and Savannah Electric know of no arrangements which may at a subsequent date result in any change in control.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
GEORGIA POWER
Transactions with management and others.
Mr. E. Jenner Wood, III is Chairman, President and Chief Executive Officer of SunTrust Bank, Central Group, and Executive Vice President of SunTrust Banks, Inc., Atlanta, Georgia. During 2005, SunTrust Bank, Inc. furnished a number of regular banking services in the ordinary course of business to Georgia Power. Georgia Power intends to maintain normal banking relations with the aforesaid bank in the future.
During 2005, Georgia Power leased a building for $78,375 and purchased uniforms for $173,008 from Riverside Manufacturing Company, and purchased reinforced steel from Anasteel & Supply Company, LLC for $171,142. Mr. William J. Vereen is Chairman, President and Chief Executive Officer of Riverside Manufacturing Company. Ms. Anna R. Cablik is President of Anasteel & Supply Company, LLC.
In 2005, Mr. James Sibert, the husband of Ms. Leslie Sibert, an executive officer of Georgia Power, was employed by Georgia Power as an Engineering Representative and received compensation of $68,536.
Also in 2005, Ms. Linda Holmes, wife of Mr. Richard Holmes, an executive officer of Georgia Power, was employed by Georgia Power as an Accounting Procedures Training Manager and received compensation of $81,819. Mr. Norman Dennis, the son-in-law of Mr. Richard Ussery, a Georgia Power director, was employed by Georgia Power as an Environmental Manager and received compensation of $219,636.
In 2005, Mr. Bradley Braswell, the son-in-law of Mr. Mickey Brown, an executive officer of Georgia Power, was employed by Georgia Power as a Customer Service Supervisor and received compensation of $77,644.
Certain business relationships.
     None.
Indebtedness of management.
     None.
Transactions with promoters.
     None.
GULF POWER
Transactions with management and others.
     None.
Certain business relationships.
     None.
Indebtedness of management.
     None.
Transactions with promoters.
     None.

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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. Arnold Tenenbaum is Chairman of the Board of Directors of FCB Financial Corp., the holding company of First Chatham Bank. During 2005, 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 Georgia Power, Gulf Power, Savannah Electric and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company’s principal public accountant for 2005 and 2004:
                 
    2005     2004  
    (in thousands)  
Georgia Power
               
Audit Fees (1)
  $ 3,128     $ 2,869  
Audit-Related Fees (2)
    8       41  
Tax Fees
    0       0  
All Other Fees
    0       0  
 
           
Total
  $ 3,136     $ 2,910  
 
           
 
               
Gulf Power
               
Audit Fees (1)
  $ 960     $ 897  
Audit-Related Fees
    0       0  
Tax Fees
    0       0  
All Other Fees
    0       0  
 
           
Total
  $ 960     $ 897  
 
           
 
               
Savannah Electric
               
Audit Fees (1)
  $ 660     $ 774  
Audit-Related Fees
    0       0  
Tax Fees
    0       0  
All Other Fees
    0       0  
 
           
Total
  $ 660     $ 774  
 
           
Southern Power
               
Audit Fees
  $ 817     $ 648  
Audit-Related Fees
    0       0  
Tax Fees
    0       0  
All Other Fees
    0       0  
 
           
Total
  $ 817     $ 648  
 
           
 
(1)   Includes services performed in connection with financing transactions.
 
(2)   Includes benefit plan and other non-statutory audit services and accounting consultations in 2005 and 2004.
     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 2005 and 2004 (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
(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 27, 2006    
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,
Chief Executive Officer and Director
(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:
Juanita P. Baranco       Zack T. Pate
Dorrit J. Bern                J. Neal Purcell
Francis S. Blake            William G. Smith, Jr.
Thomas F. Chapman     Gerald J. St. Pe’
Donald M. James
By:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: February 27, 2006

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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 27, 2006    
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 Officer)
Philip C. Raymond
Vice President and Comptroller
(Principal 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    
 
  Wallace D. Malone, Jr.   James W. Wright    
   By:      /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
   Date: February 27, 2006

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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 27, 2006    
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)
Cliff S. Thrasher
Executive Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
W. Ron Hinson
Vice President, Comptroller and Chief Accounting Officer

(Principal Accounting Officer)
                Directors:
Robert L. Brown, Jr.       D. Gary Thompson
Ronald D. Brown            Richard W. Ussery
Anna R. Cablik
               William Jerry Vereen
David M. Ratcliffe
          E. Jenner Wood, III
        By:    /s/ Wayne Boston
  (Wayne Boston, Attorney-in-fact)
        Date: February 27, 2006

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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 27, 2006    
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 and Chief Financial Officer
(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 27, 2006

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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 27, 2006    
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)
Frances V. Turnage
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)
Moses H. Feagin
Comptroller
(Principal Accounting Officer)
               Directors:
Tommy E. Dulaney           Aubrey B. Patterson, Jr.
Warren A. Hood, Jr.         George A. Schloegel
Robert C. Khayat             Philip J. Terrell
           
 
   By:   /s/ Wayne Boston    
 
    (Wayne Boston, Attorney-in-fact)    
 
         
 
   Date: February 27, 2006    

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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:   W. Craig Barrs    
 
      President and Chief Executive Officer    
 
           
 
  By:   /s/ Wayne Boston    
 
      (Wayne Boston, Attorney-in-fact)    
 
           
 
  Date: February 27, 2006    
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.
W. Craig Barrs
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
           
 
   By:   /s/ Wayne Boston    
 
    (Wayne Boston, Attorney-in-fact)    
 
       
 
   Date:  February 27, 2006

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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:   Ronnie L. Bates    
 
      President and Chief Executive Officer    
 
           
 
  By:   /s/ Wayne Boston    
 
      (Wayne Boston, Attorney-in-fact)    
 
           
 
  Date: February 27, 2006    
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.
Ronnie L. Bates
President, Chief Executive Officer and Director
(Principal Executive Officer)
Michael W. Southern
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
               Directors:
William P. Bowers            W. Dean Hudson
Thomas A. Fanning            David M. Ratcliffe
           
 
   By:   /s/ Wayne Boston    
 
    (Wayne Boston, Attorney-in-fact)    
 
       
 
   Date:  February 27, 2006

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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, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, and have issued our reports thereon dated February 27, 2006; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company (page S-2) listed in the accompanying index at Item 15. This consolidated financial statement schedule is 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 schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    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 (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-3) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 27, 2006
     
    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 (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-4) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    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 (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-5) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    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 (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-6) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    Member of
    Deloitte Touche Tohmatsu

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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 (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the merger with Georgia Power Company); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-7) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    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 consolidated financial statements of Southern Power Company and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company (page S-8) listed in the accompanying index at Item 15. This consolidated financial statement schedule is 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 schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006
     
    Member of
    Deloitte Touche Tohmatsu

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INDEX TO FINANCIAL STATEMENT SCHEDULES
                 
Schedule       Page
       
 
       
II          
            S-2  
            S-3  
            S-4  
            S-5  
            S-6  
            S-7  
            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, 2005, 2004 AND 2003

(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 (a)
                                       
2005
  $ 33,399     $ 46,193     $ 24     $ 42,106 (b)   $ 37,510  
2004
    15,812       54,248       2       36,663 (b)     33,399  
2003
    19,015       37,491       1,386       42,080 (b)     15,812  
 
(a)   Excludes provisions for uncollectible accounts in all periods for Southern Company Gas — a discontinued operation.
 
(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, 2005, 2004 AND 2003

(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
                                       
 
                                       
2005
  $ 5,404     $ 12,832     $     $10,676 (Note)   $ 7,560  
2004
    4,756       10,346           9,698 (Note)     5,404  
2003
    4,827       13,444           13,515 (Note)     4,756  
 
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, 2005, 2004 AND 2003

(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
                                       
2005
  $ 7,100     $ 24,145     $     $22,598 (Note)   $ 8,647  
2004
    5,350       20,461           18,711 (Note)     7,100  
2003
    5,825       15,577           16,052 (Note)     5,350  
 
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, 2005, 2004 AND 2003

(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
                                       
2005
  $ 2,144     $ 1,275     $     $2,285 (Note)   $ 1,134  
2004
    947       2,851           1,654 (Note)     2,144  
2003
    889       2,122           2,064 (Note)     947  
 
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, 2005, 2004 AND 2003

(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
                                       
2005
  $ 774     $ 2,610     $     $1,063 (Note)   $ 2,321  
2004
    897       1,338           1,461 (Note)     774  
2003
    718       1,947       135     1,903 (Note)     897  
 
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, 2005, 2004 AND 2003

(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
                                       
2005
  $ 878     $ 1,449     $     $1,411 (Note)   $ 916  
2004
    817       930           869 (Note)     878  
2003
    902       828           913 (Note)     817  
 
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 AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(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
                                       
2005
  $ 350     $     $     $350 (Note)   $  
2004
    350                         350  
2003
    350                         350  
 
Note:   Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.

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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.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
       Savannah Electric
             
 
  (f) 1   -   Agreement and Plan of Merger dated December 13, 2005, between Georgia Power and Savannah Electric. (Designated in Form 8-K dated December 13, 2005, File No. 1-5072, as Exhibit 2.1.)
(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.)

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     Georgia Power
             
 
  (c) 1   -   Charter of Georgia Power and amendments thereto through January 16, 2001. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in Georgia Power’s Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in Georgia Power’s Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2 and in Georgia Power’s Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2.)
 
           
 
  (c) 2   -   By-laws of Georgia Power as amended effective August 17, 2005, and as presently in effect. (Designated in Form 8-K dated August 17, 2005, File No. 1-6468, as Exhibit 3(c)2.)
     Gulf Power
             
 
  (d) 1   -   Amended and Restated Articles of Incorporation of Gulf Power and amendments thereto through November 16, 2005. (Designated in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 3.1 and in Form 8-K dated November 9, 2005, File No. 0-2429, as Exhibit 4.7.)
 
           
 
  (d) 2   -   By-laws of Gulf Power as amended effective November 2, 2005, and as presently in effect. (Designated in Form 8-K dated November 2, 2005, File No. 0-2429, as Exhibit 3.2.)
     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.)

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  (e) 2   -   By-laws of Mississippi Power as amended effective February 28, 2001, and as presently in effect. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2001, File No. 0-6849, as Exhibit 3(e)2.)
     Savannah Electric
             
 
  (f) 1   -   Charter of Savannah Electric and amendments thereto through 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 November 16, 2005. (Designated in Form 8-K dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and 4.2, in

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          Form 8-K dated January 30, 2002, File No. 1-3526, as Exhibit 4.2 and in Form 8-K dated November 8, 2005, 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.)
 
           
 
  (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.)

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  (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.)
 
           
 
  (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 February 8, 2006. (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, in Form 8-K dated November 9, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated March 8, 2005, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 11, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 13, 2006, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated February 1, 2006, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b).)
 
           
 
  (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.)

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  (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 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 December 6, 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, in Form 8-K dated January 13, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated April 12, 2005, File No. 1-6468, as Exhibit 4.1 and in Form 8-K dated November 30, 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.)

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  (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.)
     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 August 30, 2005. (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, in Form 8-K dated September 13, 2004, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated August 11, 2005, File No. 0-2429, as Exhibit 4.1 and in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 4.1.)

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  (d) 4   -   Amended and Restated Trust Agreement of Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)
 
           
 
  (d) 5   -   Amended and Restated Trust Agreement of Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.5.)
 
           
 
  (d) 6   -   Guarantee Agreement relating to Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)
 
           
 
  (d) 7   -   Guarantee Agreement relating to Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.8.)
     Mississippi Power
             
 
  (e) 1   -   Indenture dated as of September 1, 1941, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Successor Trustee, and indentures supplemental thereto through June 30, 2005. (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, in Form 8-K dated December 5, 1995, File No. 0-6849, as Exhibit 4 and in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.16.)
 
           
 
  (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 June 30, 2005. (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, in Form 8-K dated March 3, 2004, File No. 001-11229, as Exhibit 4.2 and in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.2.)
 
           
 
  (e) 3   -   Subordinated Note Indenture dated as of February 1, 1997, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indenture supplemental thereto dated as of March 22, 2002. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as

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          Exhibits 4.1 and 4.2 and in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
 
           
 
  (e) 4   -   Amended and Restated Trust Agreement of Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
 
           
 
  (e) 5   -   Guarantee Agreement relating to Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.8.)
     Savannah Electric
             
 
  (f) 1   -   Indenture dated as of March 1, 1945, between Savannah Electric and The Bank of New York, as Trustee, and indentures supplemental thereto through May 1, 1996. (Designated in Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in Savannah Electric’s Form 10-K for the year ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072, as Exhibit 4.)
 
           
 
  (f) 2   -   Senior Note Indenture dated as of March 1, 1998 between Savannah Electric and The Bank of New York, as Trustee, and indentures supplemental thereto through December 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

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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).)
 
             
#
 * (a) 2   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan.
 
             
#
 * (a) 3   -   Forms of 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.
 
             
#
  (a) 4   -   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) 5   -   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) 6   -   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) 7   -   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) 8   -   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) 9   -   Amended and Restated Change in Control Agreement between Southern Company, SCS and G. Edison Holland, Jr. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2004, File No. 1-3526, as Exhibit 10(a)13.)
 
             
#
  (a)  10   -   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.)

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#
  (a)   11   -   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)   12   -   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)   13   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy.
 
               
#
  (a)   14   -   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)   15   -   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)   16   -   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)   17   -   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)   18   -   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)   19   -   Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)92.)
 
               
#
  (a)   20   -   Amended and Restated Change in Control Agreement between Southern Company, SCS and Thomas A. Fanning, effective June 1, 2004. (Designated in Southern

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              Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)4.)
 
               
#
  (a)   21   -   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)   22   -   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)   23   -   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)   24   -   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)   25   -   Base Salaries of Named Executive Officers.
 
               
#
  (a)   26   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2004, File No. 1-3526, as Exhibit 10(a)30.)
     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   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
 
               
#
* (b)   4   -   Forms of 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)3 herein.
 
               
#
  (b)   5   -   Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
 
               
#
  (b)   6   -   Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.

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#
  (b)   7   -   The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
 
               
#
  (b)   8   -   The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
 
               
#
  (b)   9   -   Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
 
               
#
  (b)   10   -   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)   11   -   Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
 
               
#
 *  (b)   12   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
 
               
#
  (b)   13   -   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)17 herein.
 
               
#
  (b)   14   -   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)18 herein.
 
               
#
  (b)   15   -   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)19 herein.
 
               
#
  (b)   16   -   Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
 
               
#
  (b)   17   -   Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and Charles D. McCrary. See Exhibit 10(a)14 herein.
 
               
#
  (b)   18   -   Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and C. Alan Martin, effective June 1, 2004. (Designated in Alabama Power’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(b)4.)
 
               
#
 *  (b)   19   -   Base Salaries of Named Executive Officers.

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#
      (b)   20   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Alabama Power’s Form 10-K for the year ended December 31, 2004, File No. 1-3164, as Exhibit 10(b)20.)
     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   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
 
                   
#
  *   (c)   7   -   Forms of 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)3 herein.
 
                   
#
      (c)   8   -   Southern Company Deferred Compensation Plan as amended and restated effective January 1, 2004. See Exhibit 10(a)5 herein.
 
                   
#
      (c)   9   -   Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
 
                   
#
      (c)   10   -   The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
 
                   
#
      (c)   11   -   The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
 
                   
#
      (c)   12   -   Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.

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#
      (c)   13   -   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)   14   -   Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
 
                   
#
  *   (c)   15   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
 
                   
#
      (c)   16   -   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)17 herein.
 
                   
#
      (c)   17   -   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)18 herein.
 
                   
#
      (c)   18   -   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)19 herein.
 
                   
#
      (c)   19   -   Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
 
                   
#
      (c)   20   -   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)   21   -   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)   22   -   Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and Michael D. Garrett. See Exhibit 10(a)24 herein.
 
                   
#
      (c)   23   -   Separation Agreement, dated as of January 4, 2006, between Georgia Power and William C. Archer III. (Designated in Form 8-K dated January 4, 2006, File No. 1-6468, as Exhibit 10.1.)
 
                   
#
      (c)   24   -   Consulting Agreement, dated as of January 4, 2006, between Georgia Power and William C. Archer III. (Designated in Form 8-K dated January 4, 2006, File No. 1-6468, as Exhibit 10.2.)

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Table of Contents

             
#
  *   (c)   25   -   Base Salaries of Named Executive Officers.
 
                   
#
      (c)   26   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 2004, File No. 1-6468, as Exhibit 10(c)24.)
     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   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
 
                   
#
  *   (d)   7   -   Forms of 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)3 herein.
 
                   
#
      (d)   8   -   Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
 
                   
#
      (d)   9   -   Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
 
                   
#
      (d)   10   -   The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
 
                   
#
      (d)   11   -   Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)22 herein.

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#
      (d)   12   -   The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
 
                   
#
      (d)   13   -   Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated effective January 1, 2000 and First Amendment thereto. (Designated in Gulf Power’s Form 10-K for the year ended December 31, 2000, File No. 0-2429 as Exhibit 10(d)33.)
 
                   
#
      (d)   14   -   Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
 
                   
#
  *   (d)   15   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
 
                   
#
      (d)   16   -   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)17 herein.
 
                   
#
      (d)   17   -   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)18 herein.
 
                   
#
      (d)   18   -   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)19 herein.
 
                   
#
      (d)   19   -   Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
 
                   
#
  *   (d)   20   -   Base Salaries of Named Executive Officers.
 
                   
#
      (d)   21   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Gulf Power’s Form 10-K for the year ended December 31, 2004, File No. 0-2429, as Exhibit 10(d)20.)
 
     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.

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                  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.
 
                   
#
  *   (e)   4   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
 
                   
#
  *   (e)   5   -   Forms of 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)3 herein.
 
                   
#
      (e)   6   -   Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
 
                   
#
      (e)   7   -   Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
 
                   
#
      (e)   8   -   The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
 
                   
#
      (e)   9   -   Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
 
                   
#
      (e)   10   -   The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
 
                   
#
      (e)   11   -   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)   12   -   Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
 
                   
#
  *   (e)   13   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
 
                   
#
      (e)   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)17 herein.

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#
    (e)  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)18 herein.
 
               
#
    (e)  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)19 herein.
 
               
#
    (e)  17   -   Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
 
               
#
*   (e)  18   -   Base Salaries of Named Executive Officers.
 
               
#
    (e)  19   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2004, File No. 001-11229, as Exhibit 10(e)20.)
 
               
 
    (e)  20   -   Credit Agreement, dated as of October 20, 2005, by and among Mississippi Power and the lenders named therein. (Designated in Form 8-K dated October 20, 2005, File No. 001-11229, as Exhibit 10.1.)
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   -   First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
 
                   
#
  *   (f)   4   -   Forms of 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)3 herein.
 
                   
#
      (f)   5   -   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)   6   -   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.)

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Table of Contents

             
#
      (f)   7   -   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)   8   -   Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
 
                   
#
      (f)   9   -   The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
 
                   
#
      (f)   10   -   Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
 
                   
#
      (f)   11   -   Southern Company Deferred Compensation Plan, as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
 
                   
#
      (f)   12   -   The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
 
                   
#
      (f)   13   -   Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
 
                   
#
  *   (f)   14   -   First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
 
                   
#
      (f)   15   -   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)   16   -   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)   17   -   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)17 herein.
 
                   
#
      (f)   18   -   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)18 herein.
 
                   
#
      (f)   19   -   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)19 herein.

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Table of Contents

             
#
      (f)   20   -   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)   21   -   Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
 
                   
#
      (f)   22   -   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)   23   -   Base Salaries of Named Executive Officers.
 
                   
#
      (f)   24   -   Summary of Non-Employee Director Compensation Arrangements. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2004, File No. 1-5072, as Exhibit 10(f)23.)
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 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)   4   -   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)   5   -   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)   6   -   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)   7   -   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.)

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Table of Contents

             
 
      (g)   8   -   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.)
 
                   
 
      (g)   9   -   Multi-Year Credit Agreement among Southern Power, Citibank N.A., as the administrative agent, and the lenders listed therein dated as of June 10, 2005. (Designated in Southern Power’s Form 10-Q for the quarter ended June 30, 2005, File No. 333-98553 as Exhibit 10(g)1.)
 
                   
 
      (g)   10   -   Purchase and Sale Agreement, by and between CP Oleander, LP and CP Oleander I, Inc., as Sellers, Constellation Power, Inc. and SP Newco I LLC and SP Newco II LLC, as Purchasers, and Southern Power, as Purchaser’s Parent, for the Sale of Partnership Interests of Oleander Power Project, LP, dated as of April 8, 2005. (Designated in Form 8-K dated June 7, 2005, File No. 333-98553, as Exhibit 2.1 and incorporated herein by reference.)
 
                   
 
  *   (g)   11   -   Cooperative Agreement between United States Department of Energy and Southern Company Services, Inc. dated as of February 22, 2006. (Southern Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the Securities and Exchange Commission. Southern Power has omitted such portions from this filing and filed them separately with the Securities and Exchange Commission.)
(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.
     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.

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(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
             
 
  Omitted pursuant to General Instruction I(2)(b) of Form 10-K.
(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.

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       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.
       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.

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Alabama Power
                     
*
  (b)     1     -   Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (b)     2     -   Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Georgia Power
                     
*
  (c)     1     -   Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (c)     2     -   Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Gulf Power
                     
*
  (d)     1     -   Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (d)     2     -   Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
                     
*
  (e)     1     -   Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (e)     2     -   Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Savannah Electric
                     
*
  (f)     1     -   Certificate of Savannah Electric’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (f)     2     -   Certificate of Savannah Electric’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Southern Power
                     
*
  (g)     1     -   Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
                   
*
  (g)     2     -   Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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(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.

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