SOUTHERN COMPANY

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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


Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.

1-3526	The Southern Company	58-0690070
	(A Delaware Corporation)
	270 Peachtree Street, N.W.
	Atlanta, Georgia 30303
	(404) 506-5000
1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18th Street
	Birmingham, Alabama 35291
	(205) 257-1000
1-6468	Georgia Power Company	58-0257110
	(A Georgia Corporation)
	241 Ralph McGill Boulevard, N.E.
	Atlanta, Georgia 30308
	(404) 506-6526
0-2429	Gulf Power Company	59-0276810
	(A Maine Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111
001-11229	Mississippi Power Company	64-0205820
	(A Mississippi Corporation)
	2992 West Beach
	Gulfport, Mississippi 39501
	(228) 864-1211
1-5072	Savannah Electric and Power Company	58-0418070
	(A Georgia Corporation)
	600 East Bay Street
	Savannah, Georgia 31401
	(912) 644-7171
333-98553	Southern Power Company	58-2598670
	(A Delaware Corporation)
	270 Peachtree Street, N.W.
	Atlanta, Georgia 30303
	(404) 506-5000

Securities registered pursuant to Section 12(b) of the Act:¹

Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is listed on the New York Stock Exchange.


Title of each class		Registrant

Common Stock, $5 par value		The Southern Company

Mandatorily redeemable preferred securities, $25 liquidation amount
7.125% Trust Preferred Securities²



Class A preferred, cumulative, $25 stated capital		Alabama Power Company
5.20% Series	5.83% Series
5.30% Series

Senior Notes
5 5/8% Series AA



Senior Notes		Georgia Power Company
5.90% Series O	6% Series R
5.75% Series T	6% Series W

Mandatorily redeemable preferred securities, $25 liquidation amount
7 1/8% Trust Preferred Securities³
5 7/8% Trust Preferred Securities⁴



Senior Notes		Gulf Power Company
5.25% Series H	5.75% Series I
5.875% Series J

Mandatorily redeemable preferred securities, $25 liquidation amount
7.375% Trust Preferred Securities⁵

¹		As of December 31, 2004.

²		Issued by Southern Company Capital Trust VI and guaranteed by The Southern Company.

³		Issued by Georgia Power Capital Trust V and guaranteed by Georgia Power Company.

⁴		Issued by Georgia Power Capital Trust VII and guaranteed by Georgia Power Company.

⁵		Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company.



Senior Notes				Mississippi Power Company
5 5/8% Series E

Depositary preferred shares, each representing one-fourth of a share of preferred stock, cumulative, $100 par value
5.25% Series

Mandatorily redeemable preferred securities, $25 liquidation amount
7.20% Trust Originated Preferred Securities⁶



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

Senior Notes
5.75% Series G

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


Title of each class			Registrant

Preferred stock, cumulative, $100 par value			Alabama Power Company
4.20% Series	4.60% Series	4.72% Series
4.52% Series	4.64% Series	4.92% Series

Class A Preferred Stock, cumulative, $100,000 stated capital
Flexible Money Market (Series 2003A)



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



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



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

⁶		Issued by Mississippi Power Capital Trust II and guaranteed by Mississippi Power Company.

⁷		As of December 31, 2004.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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


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

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


	Description of	Shares Outstanding
Registrant	Common Stock	at January 31, 2005
The Southern Company	Par Value $5 Per Share		742,831,334
Alabama Power Company	Par Value $40 Per Share		8,250,000
Georgia Power Company	Without Par Value		7,761,500
Gulf Power Company	Without Par Value		992,717
Mississippi Power Company	Without Par Value		1,121,000
Savannah Electric and Power Company	Par Value $5 Per Share		10,844,635
Southern Power Company	Par Value $0.01 Per Share		1,000

Documents incorporated by reference: specified portions of The Southern Company’s Proxy Statement relating to the 2005 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Information Statements of Alabama Power Company, Georgia Power Company, Gulf Power Company and Mississippi Power Company relating to each of their respective 2005 Annual Meetings of Shareholders are incorporated by reference into PART III.

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

This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Savannah Electric and Power Company and Southern Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.

DEFINITIONS

When used in Items 1 through 5 and Items 9A through 15, the following terms will have the meanings indicated.


Term		Meaning

AEC		Alabama Electric Cooperative, Inc.
AFUDC		Allowance for Funds Used During Construction
Alabama Power		Alabama Power Company
AMEA		Alabama Municipal Electric Authority
Clean Air Act		Clean Air Act Amendments of 1990
Dalton		City of Dalton, Georgia
DOE		United States Department of Energy
Energy Act		Energy Policy Act of 1992
Energy Solutions		Southern Company Energy Solutions, Inc.
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
FMPA		Florida Municipal Power Agency
FPC		Florida Power Corporation
FP&L		Florida Power & Light Company
Georgia Power		Georgia Power Company
Gulf Power		Gulf Power Company
Holding Company Act		Public Utility Holding Company Act of 1935, as amended
IBEW		International Brotherhood of Electrical Workers
IPP		Independent power producer
IRP		Integrated Resource Plan
IRC		Internal Revenue Code
IRS		Internal Revenue Service
JEA		Jacksonville Electric Authority
KUA		Kissimmee Utility Authority
MEAG		Municipal Electric Authority of Georgia
Mirant		Mirant Corporation
Mississippi Power		Mississippi Power Company
Moody’s		Moody’s Investors Service
NRC		Nuclear Regulatory Commission
OPC		Oglethorpe Power Corporation
OUC		Orlando Utilities Commission
PPA		Power Purchase Agreement
Progress Energy		Florida Power Corporaton, d/b/a Progress Energy Florida, Inc.
PSC		Public Service Commission
registrants		The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Savannah Electric and Power Company and Southern Power Company
retail operating companies		Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company

DEFINITIONS
(continued)



RFP		Request for Proposal
RTO		Regional Transmission Organization
RUS		Rural Utility Service (formerly Rural Electrification Administration)
S&P		Standard and Poor’s, a division of The McGraw-Hill Companies
Savannah Electric		Savannah Electric and Power Company
SCS		Southern Company Services, Inc. (the system service company)
SEC		Securities and Exchange Commission
SEGCO		Southern Electric Generating Company
SEPA		Southeastern Power Administration
SERC		Southeastern Electric Reliability Council
SMEPA		South Mississippi Electric Power Association
Southern Company		The Southern Company
Southern Company GAS		Southern Company Gas LLC
Southern Company system		Southern Company, the retail operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless, Southern Company GAS and other subsidiaries
Southern Holdings		Southern Company Holdings, Inc.
SouthernLINC Wireless		Southern Communications Services, Inc.
Southern Nuclear		Southern Nuclear Operating Company, Inc.
Southern Power		Southern Power Company
Southern Telecom		Southern Telecom, Inc.
Super Southeast		Southern Company’s traditional service territory, Alabama, Florida, Georgia and Mississippi, plus the surrounding States of Kentucky, Louisiana, North Carolina, South Carolina, Tennessee and Virginia
TVA		Tennessee Valley Authority

iii

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, retail sales growth, storm damage cost recovery, environmental regulations and expenditures, projections for postretirement benefit trust contributions, completion of construction projects and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•   current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, IRS audits and Mirant related matters;

•   the effects, extent and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;

•   variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

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

•   advances in technology;

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

•   the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

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

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

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

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

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

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

•   the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;

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

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

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

•   other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.

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

PART I

Item 1. BUSINESS

Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern Company is domesticated under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. Southern Company owns all the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric, each of which is an operating public utility company. The retail operating companies supply electric service in the states of Alabama, Georgia, Florida, Mississippi and Georgia, respectively. More particular information relating to each of the retail operating companies is as follows:

Alabama Power is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company and Houston Power Company. The predecessor Alabama Power Company had had a continuous existence since its incorporation in 1906.

Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930, and admitted to do business in Alabama on September 15, 1948.

Gulf Power is a corporation which was organized under the laws of the State of Maine on November 2, 1925, and admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984.

Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924, and was admitted to do business in Mississippi on December 23, 1924, and in Alabama on December 7, 1962.

Savannah Electric is a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921.

In addition, Southern Company owns all of the common stock of Southern Power, which is also an operating public utility company. Southern Power constructs, owns and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Southern Power is a corporation organized under the laws of Delaware on January 8, 2001, and admitted to do business in Alabama, Florida and Georgia on January 10, 2001 and in Mississippi on January 30, 2001.

Southern Company also owns all the outstanding common stock of SouthernLINC Wireless, Southern Company GAS, Southern Nuclear, SCS, Southern Telecom, Southern Holdings and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Company GAS, which began operation in August 2002, is a competitive retail natural gas marketer serving communities in Georgia. Southern Nuclear provides services to Alabama Power’s and Georgia Power’s nuclear plants. SCS is the system service company providing, at cost, specialized services to Southern Company and its subsidiary companies. Southern Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses.

Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power and Georgia Power are each entitled to one-half of SEGCO’s capacity and energy. Alabama Power acts as SEGCO’s agent in the operation of SEGCO’s units and furnishes coal to SEGCO as fuel for its units. SEGCO also owns three 230,000 volt transmission lines extending from Plant Gaston to the Georgia state line at which point connection is made with the Georgia Power transmission line system.

I-1

See Note 10 to the financial statements of Southern Company in Item 8 herein for additional information regarding Southern Company’s segment and related information.

The registrants’ Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are made available on Southern Company’s website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company’s internet address is http://www.southerncompany.com.

The SOUTHERN System

Retail Operating Companies

The transmission facilities of each of the retail operating companies are connected to the respective company’s own generating plants and other sources of power and are interconnected with the transmission facilities of the other retail operating companies and SEGCO by means of heavy-duty high voltage lines. For information on Georgia Power’s integrated transmission system, see BUSINESS — “Territory Served by the Utilities” in Item 1 herein for additional information.

Operating contracts covering arrangements in effect with principal neighboring utility systems provide for capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. Additionally, the retail operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy Corporation, South Carolina Electric & Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations and other matters affecting the reliability of bulk power supply. The retail operating companies have joined with other utilities in the Southeast (including those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the retail operating companies are represented on the National Electric Reliability Council.

An intra-system interchange agreement provides for coordinating operations of the power producing facilities of the retail operating companies and Southern Power and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the retail operating companies and Southern Power to provide the most economical sources of power consistent with reliable operation. The resulting benefits and savings are apportioned among each of the companies.

SCS has contracted with Southern Company, each retail operating company, Southern Power, Southern Nuclear, SEGCO and other subsidiaries to furnish, at direct or allocated cost and upon request, the following services: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures and other services with respect to business and operations and power pool transactions. Southern Power, Southern Company GAS, SouthernLINC Wireless and Southern Telecom have also secured from the retail operating companies certain services which are furnished at cost.

Southern Nuclear has contracts with Alabama Power to operate Plant Farley and with Georgia Power to operate Plants Hatch and Vogtle. See BUSINESS — “Regulation — Atomic Energy Act of 1954” in Item 1 herein for additional information.

Southern Power

Southern Power is an electric wholesale generation subsidiary with market-based rates. Southern Power constructs, owns and manages generating facilities and sells the output under long-term, fixed-price capacity contracts both to unaffiliated wholesale purchasers as well as to the retail operating companies (under PPAs approved by the respective PSCs). Southern Power’s business activities are not subject to traditional state regulation of utilities but are subject to regulation by the

I-2

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

Other Business

In June 2002, Southern Company formed a wholly-owned subsidiary, Southern Company GAS. Southern Company GAS operates as a retail gas marketer in the State of Georgia. Southern Company GAS completed its acquisition out of bankruptcy from The New Power Company (New Power) and began operations in July 2002. Southern Company GAS also purchased proprietary risk management software and hardware systems, natural gas inventory and accounts receivable from New Power. The total purchase price was approximately $60 million. Southern Company GAS has a 12.2% market share as of December 31, 2004.

Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in leveraged leases and synthetic fuel products, in addition to Southern Company Energy Solutions LLC, which provides energy services.

In 1996, SouthernLINC Wireless began serving Southern Company’s retail operating companies and marketing its services to non-affiliates within the Southeast. Its system covers approximately 127,000 square miles and combines the functions of two-way radio dispatch, cellular phone, short text and numeric messaging and wireless internet access and data transfer.

These continuing efforts to invest in and develop new business opportunities offer potential returns exceeding those of rate-regulated operations. However, these activities also involve a higher degree of risk.

Risk Factors

In addition to the other information in this Form 10-K and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries. Some or all of these factors may apply to Southern Company and/or its subsidiaries.

Risks Related to the Energy Industry

Southern Company is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Southern Company.

Southern Company is subject to substantial regulation from federal, state and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of their businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of fossil-fuel, hydroelectric and nuclear generating facilities. For example, the rates charged to wholesale customers by the retail operating companies and by Southern Power must be approved by the FERC. In addition, the respective state PSCs must approve the retail operating companies’ rates for retail customers. Southern Company believes the necessary permits, approvals and certificates have been obtained for its existing operations and that its business is conducted in accordance with applicable laws; however, Southern Company is unable to predict the impact on its operating results from future regulatory activities of these agencies.

Southern Company is also subject to regulation by the SEC under the Holding Company Act. The rules and regulations promulgated under the Holding Company Act impose a number of restrictions on the

I-3

operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, acquisitions and dispositions of utility assets or of securities of utility companies and acquisitions of other businesses. The Holding Company Act also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. The Holding Company Act requires that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions.

The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries cannot now be predicted. Changes in regulation or the imposition of additional regulations could influence Southern Company’s operating environment and may result in substantial costs to Southern Company.

General Risks Related to Operation of Southern Company’s Utility Subsidiaries

The regional power market in which Southern Company and its subsidiaries compete has changing transmission regulatory structures, which could affect the ownership of these assets and related revenues and expenses.

The retail operating companies currently own and operate transmission facilities as part of a vertically integrated utility. Transmission revenues are not separated from generation and distribution revenues in their approved retail rates. Federal governmental authorities are advocating the formation of RTOs and are proposing the adoption of new regulations that would impact electric markets, including the transmission regulatory structure. Under this new transmission regulatory structure, the retail operating companies would transfer functional control (but not ownership) of their transmission facilities to an independent third party. Because it remains unclear how RTOs will develop or what new market rules will be established, Southern Company is unable to assess fully the impact that these developments may have on its business. Southern Company’s revenues, expenses, assets and liabilities could be adversely affected by changes in the transmission regulatory structure in its regional power market.

Certain events in the energy markets that are beyond Southern Company’s control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets. The reaction to these events may result in new laws or regulations related to Southern Company’s business operations or the accounting treatment of its existing operations which could have a negative impact on Southern Company’s net income or access to capital.

As a result of the energy crisis in California during the summer of 2001, the filing of bankruptcy by Enron Corporation, investigations by governmental authorities into energy trading activities and the August 2003 power outage in the Northeast, companies in regulated and unregulated electric utility businesses have been under an increased amount of public and regulatory scrutiny with respect to, among other things, accounting practices, financial disclosures and relationships with independent auditors. The capital markets and ratings agencies also have increased their level of scrutiny. This increased scrutiny could lead to substantial changes in laws and regulations affecting Southern Company, including new accounting standards that could change the way Southern Company is required to record revenues, expenses, assets and liabilities. These types of disruptions in the industry and any resulting regulations may have a negative impact on Southern Company’s net income or access to capital.

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

Increased competition, which may result from restructuring efforts, could have a significant adverse financial impact on Southern Company and its retail operating companies. Increased competition could result in increased pressure to lower the cost of electricity. Any adoption in the territories served by the retail operating companies of retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on Southern Company and the retail operating companies due to an impairment of assets, a loss of retail customers, lower profit margins, an inability to recover reasonable costs or increased costs of capital. Southern Company cannot

I-4

predict if or when it will be subject to changes in legislation or regulation, nor can Southern Company predict the impact of these changes.

Additionally, the electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. As a result of the Public Utility Regulatory Policies Act of 1978 and the Energy Act, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. In 1996, the FERC issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale power customers.

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

Each of the retail operating companies and Southern Power have authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities’ applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

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

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

I-5

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

Risks Related to Environmental Regulation

Southern Company’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws and the incurrence of environmental liabilities could harm Southern Company’s cash flow and profitability.

Southern Company and its subsidiaries are subject to extensive federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires Southern Company to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of its facilities. These expenditures are significant and Southern Company expects that they will increase in the future. For example, construction expenditures for achieving compliance with Title IV of the Clean Air Act totaled approximately $400 million. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled approximately $1.1 billion through 2004 with an additional $500 million committed through 2007 for the states of Alabama and Georgia.

Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. Although the ultimate outcome of such litigation cannot be predicted, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the financial condition of Southern Company and its subsidiaries.

If Southern Company fails to comply with environmental laws and regulations, even if caused by factors beyond its control, that failure may result in the assessment of civil or criminal penalties and fines against Southern Company. The EPA has filed civil actions against Alabama Power, Georgia Power and Savannah Electric alleging violations of the new source review provisions of the Clean Air Act. The EPA has also issued notices of violation to Gulf Power and Mississippi Power. In addition, Georgia Power is a party to a civil suit regarding alleged violations of the Clean Air Act at four units of Plant Wansley. Attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and/or could require payment of substantial penalties.

Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to Southern Company. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on Southern Company’s facilities or increased compliance costs which may not be fully recoverable from Southern Company’s customers and would therefore reduce Southern Company’s net income. The cost impact of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

Risks Related to Southern Company and its Business

Southern Company may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or repay funds to Southern Company.

Southern Company is a holding company and, as such, Southern Company has no operations of its own. Southern Company’s ability to meet its financial obligations and to pay dividends on its common stock at the current rate is primarily dependent on the earnings and cash flows of its subsidiaries and their ability to pay upstream dividends or to repay funds to Southern

I-6

Company. Prior to funding Southern Company, Southern Company’s subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. In addition, the Holding Company Act rules limit the dividends that Southern Company’s subsidiaries may pay from unearned surplus.

Southern Company’s financial performance may be adversely affected if its subsidiaries are unable to successfully operate their facilities.

Southern Company’s financial performance depends on the successful operation of its subsidiaries’ electric generating, transmission and distribution facilities. Operating these facilities involves many risks, including:

•   operator error and breakdown or failure of equipment or processes;

•   operating limitations that may be imposed by environmental or other regulatory requirements;

•   labor disputes;

•   terrorist attacks;

•   fuel supply interruptions; and

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

A decrease or elimination of revenues from power produced by the electric generating facilities or an increase in the cost of operating the facilities would reduce Southern Company’s net income and could decrease or eliminate funds available to Southern Company.

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

Through its subsidiaries, Southern Company’s revenues depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, or the failure to renew the PPAs, could have a negative impact on Southern Company’s earnings.

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

Southern Company and its subsidiaries may incur additional costs or delays in power plant construction and may not be able to recover their investment. Southern Company’s facilities require ongoing capital expenditures.

Certain of the retail operating companies and Southern Power are in the process of constructing new generating facilities. Southern Company intends to continue its strategy of developing and constructing other new facilities and expanding existing facilities. The completion of these facilities without delays or cost overruns is subject to substantial risks, including:

•   shortages and inconsistent quality of equipment, materials and labor;

•   work stoppages;

•   permits, approvals and other regulatory matters;

•   adverse weather conditions;

•   unforeseen engineering problems;

•   environmental and geological conditions;

•   delays or increased costs to interconnect its facilities to transmission grids;

•   unanticipated cost increases; and

•   attention to other projects.

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

I-7

facility, or if a retail operating company or Southern Power decides to delay or cancel construction of a facility, it may not be able to recover its investment in that facility. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the results of operations and financial position of a retail operating company or Southern Power. Furthermore, if construction projects are not completed according to specification, a retail operating company or Southern Power may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced earnings.

Once facilities come into commercial operation, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the retail operating companies’ existing facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations.

Changes in technology may make Southern Company’s electric generating facilities less competitive.

A key element of Southern Company’s business model is that generating power at central power plants achieves economies of scale and produces power at relatively low cost. There are other technologies that produce power, most notably fuel cells, microturbines, windmills and solar cells. It is possible that advances in technology will reduce the cost of alternative methods of producing power to a level that is competitive with that of most central power station electric production. If this were to happen and if these technologies achieved economies of scale, Southern Company’s market share could be eroded, and the value of its electric generating facilities could be reduced. Changes in technology could also alter the channels through which retail electric customers buy power, which could reduce Southern Company’s revenues or increase expenses.

Operation of nuclear facilities involves inherent risks, including environmental, health, regulatory, terrorism and financial risks that could result in fines or the closure of Southern Company’s nuclear units, and which may present potential exposures in excess of Southern Company’s insurance coverage.

Southern Company owns six nuclear units through Alabama Power (two units) and through Georgia Power, which holds undivided interests in, and contracts for operation of, four units. These six nuclear units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 9.5% of Southern Company’s generation capacity as of December 31, 2004. Southern Company’s nuclear facilities are subject to environmental, health and financial risks such as on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities and the threat of a possible terrorist attack. Southern Company maintains decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of Southern Company’s insurance coverage.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Recent NRC orders related to increased security measures and any future safety requirements promulgated by the NRC could require Southern Company to make substantial operating and capital expenditures at its nuclear plants. In addition, although Southern Company has no reason to anticipate a serious nuclear incident at its plants, if an incident did occur, it could result in substantial costs to Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.

Southern Company’s nuclear units require licenses that, in some cases, need to be renewed or extended in order to continue operating beyond their initial forty-year terms. As a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.

I-8

Southern Company’s generation and energy marketing operations are subject to risks, many of which are beyond its control, that may reduce Southern Company’s revenues and increase its costs.

Southern Company’s generation and energy marketing operations are subject to changes in power prices or fuel costs, which could increase the cost of producing power or decrease the amount Southern Company receives from the sale of power. The market prices for these commodities may fluctuate over relatively short periods of time. Southern Company attempts to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers through retail fuel cost recovery or in its PPAs. Among the factors that could influence power prices and fuel costs are:

•   prevailing market prices for coal, natural gas, fuel oil and other fuels used in Southern Company’s generation facilities, including associated transportation costs, and supplies of such commodities;

•   demand for energy and the extent of additional supplies of energy available from current or new competitors;

•   liquidity in the general wholesale electricity market;

•   weather conditions impacting demand for electricity;

•   seasonality;

•   transmission or transportation constraints or inefficiencies;

•   availability of competitively priced alternative energy sources;

•   forced or unscheduled plant outages for us, our competitors or third party providers;

•   the financial condition of market participants;

•   the economy in the service territory and in general, including the impact of economic conditions on industrial and commercial demand for electricity;

•   natural disasters, wars, embargos, acts of terrorism and other catastrophic events; and

•   federal, state and foreign energy and environmental regulation and legislation.

Certain of these factors could increase Southern Company’s expenses. For the retail operating companies, such increases may not be fully recoverable through rates. Other of these factors could reduce Southern Company’s revenues.

The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the results of operations of Southern Company and its subsidiaries.

Southern Company and its subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage their commodity and financial market risks and, to a lesser extent, engage in limited trading activities. Southern Company and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or if a counterparty fails to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

Southern Company may not be able to obtain adequate fuel supplies, which could limit its ability to operate its facilities.

Southern Company purchases fuel from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, weather, labor relations or environmental regulations affecting Southern Company’s fuel suppliers, could limit Southern Company’s ability to operate its facilities, and thus, reduce its net income.

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

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

I-9

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

Demand for power could exceed Southern Company’s supply capacity, resulting in increased costs to Southern Company for purchasing capacity in the open market or building additional generation capabilities.

Southern Company is currently obligated to supply power to regulated retail and wholesale customers under long-term PPAs. At peak times, the demand for power required to meet this obligation could exceed Southern Company’s available generation capacity. Market or competitive forces may require that Southern Company purchase capacity on the open market or build additional generation capabilities. Because regulators may not permit the retail operating companies to pass all of these purchase or construction costs on to their customers, the retail operating companies may not be able to recover any of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the retail operating companies’ recovery in customers’ rates. Under Southern Power’s long-term fixed price PPAs, Southern Power would not have the ability to recover any of these costs.

Southern Company’s operating results are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.

Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, Southern Company’s overall operating results in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce Southern Company’s revenues, net income, available cash and borrowing ability.

Risks Related to Market and Economic Volatility

Southern Company’s business is dependent on its ability to successfully access capital markets. Southern Company’s inability to access capital may limit its ability to execute its business plan or pursue improvements and make acquisitions that Southern Company may otherwise rely on for future growth.

Southern Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations. If Southern Company is not able to access capital at competitive rates, its ability to implement its business plan or pursue improvements and make acquisitions that Southern Company may otherwise rely on for future growth will be limited. Southern Company believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of Southern Company’s credit rating may increase its cost of borrowing or adversely affect its ability to raise capital through the issuance of securities or other borrowing arrangements. Such disruptions could include:

•   an economic downturn;

•   the bankruptcy of an unrelated energy company;

•   capital market conditions generally;

•   market prices for electricity and gas;

•   terrorist attacks or threatened attacks on Southern Company’s facilities or unrelated energy companies;

•   war or threat of war; or

•   the overall health of the utility industry.

Southern Company is subject to risks associated with a changing economic environment, including Southern Company’s ability to obtain insurance, the financial stability of its customers and Southern Company’s ability to raise capital.

The September 11, 2001 terrorist attacks, the continuing threat of terrorism and the related military action by the United States have affected the nation’s economy and financial markets. The insurance industry has also been disrupted by these events. The availability of insurance covering risks Southern Company and its competitors typically insure against may decrease, and the insurance that Southern Company is able to obtain

I-10

may have higher deductibles, higher premiums and more restrictive policy terms. Any economic downturn or disruption of financial markets could constrain the capital available to Southern Company’s industry and could reduce Southern Company’s access to funding for its operations, as well as the financial stability of its customers and counterparties. These factors could adversely affect Southern Company’s subsidiaries’ ability to achieve energy sales growth, thereby decreasing Southern Company’s level of future earnings.

Construction Programs

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Construction expenditures during 2005 through 2007 by the retail operating companies, Southern Power and other subsidiaries are estimated as follows:



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

	$	2,231	$	2,460	$	3,240

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

I-11

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



	Southern
	Company		Alabama		Georgia		Gulf		Mississippi		Savannah		Southern
	System*		Power		Power		Power		Power		Electric		Power

New generation	$	89	$	—	$	49	$	—	$	—	$	10	$	31
Other generating
facilities including associated plant substations		770		387		240		82		29		6		26
New business		402		141		199		26		23		12		—
Transmission		337		111		191		11		15		9		—
Joint line and substation		39		—		34		5		—		—		—
Distribution		253		130		71		22		15		13		—
Nuclear fuel		142		78		64		—		—		—		—
General plant		199		55		63		8		6		2		—

	$	2,231	$	902	$	911	$	154	$	88	$	52	$	57

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

The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing cost of construction labor, equipment and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Under Georgia law, Georgia Power and Savannah Electric each are required to file an Integrated Resource Plan for approval by the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the construction of new power plants and new PPAs. See BUSINESS — “Rate Matters — Integrated Resource Planning” in Item 1 herein and Note 3 to the financial statements under “Plant McIntosh Construction Project” of Southern Company, Georgia Power and Savannah Electric and Note 2 to the financial statements of Southern Power in Item 8 herein under “Plant McIntosh Construction Project” for additional information regarding the acquisition by Georgia Power and Savannah Electric of the Plant McIntosh construction project and the withdrawal of the PPAs with Southern Power for Plant McIntosh’s capacity.

See BUSINESS — “Regulation — Environmental Statutes and Regulations” in Item 1 herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information concerning Alabama Power’s, Georgia Power’s and Southern Power’s joint ownership of certain generating units and related facilities with certain non-affiliated utilities.

Financing Programs

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

I-12

Fuel Supply

The retail operating companies’ and SEGCO’s supply of electricity is derived predominantly from coal. Southern Power’s supply of electricity is primarily fueled by natural gas. The sources of generation for the years 2002 through 2004 are shown below:


		Coal		Nuclear		Hydro			Gas		Oil
		%		%		%			%		%

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

* Less than 0.5%.
** Not applicable.

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


	2002		2003		2004


Alabama Power		1.44		1.54		1.69

Georgia Power		1.42		1.46		1.55

Gulf Power		2.08		2.11		2.32

Mississippi Power		2.03		1.95		2.47

Savannah Electric		2.44		2.38		2.57

SEGCO		1.53		1.54		1.60

Southern Power		3.17		3.79		4.36

Southern Company system — weighted average		1.58		1.66		1.87

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

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

I-13

in place for their natural gas burn requirements. For 2005, the retail operating companies, Southern Power and Southern Company GAS have contracted for 103 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 14 years. In addition to gas supply, the retail operating companies, Southern Power and Southern Company GAS have contracts in place for both firm gas transportation and storage. Management believes that these contracts provide sufficient natural gas supplies, transportation and storage to ensure normal operations of the Southern Company system’s natural gas generating units.

Changes in fuel prices to the retail operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See BUSINESS — “Rate Matters — Rate Structure” in Item 1 herein for additional information.

Alabama Power and Georgia Power have numerous contracts covering a portion of their nuclear fuel needs for uranium, conversion services, enrichment services and fuel fabrication. These contracts have varying expiration dates and most are short to medium term (less than 10 years). Management believes that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment of normal operations of the Southern Company system’s nuclear generating units.

Alabama Power and Georgia Power have contracts with the DOE that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998, as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity is available at Plant Farley to maintain full-core discharge capability until the refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively. Construction of an on-site dry storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units. Also, the facility will be able to be expanded to provide storage through 2025. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry storage facility became operational in 2000 and can be expanded to accommodate spent fuel through the life of the Plant.

The Energy Act established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants, including Alabama Power and Georgia Power. This assessment is being paid over a 15-year period ending in 2008. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. See Note 1 to the financial statements of Southern Company, Alabama Power and Georgia Power under the heading “Fuel Costs” in Item 8 herein for additional information.

Territory Served by the Utilities

The territory in which the retail operating companies provide electric service comprises most of the states of Alabama and Georgia together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems which obtain some or all of their power requirements either directly or indirectly from the retail operating companies. The territory has an area of approximately 120,000 square miles and an estimated population of approximately 11 million.

Alabama Power is engaged, within the State of Alabama, in the generation and purchase of electricity and the distribution and sale of such electricity at retail in over 1,000 communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. Alabama Power also supplies steam service in downtown Birmingham. Alabama Power owns coal reserves near its Gorgas Steam Electric Generating Plant and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances.

Georgia Power is engaged in the generation and purchase of electricity and the transmission, distribution and sale of such electricity within the State of Georgia at retail in over 600 communities, as well as in rural areas,

I-14

and at wholesale currently to OPC, MEAG, Dalton and the City of Hampton.

Gulf Power is engaged, within the northwestern portion of Florida, in the generation and purchase of electricity and the distribution and sale of such electricity at retail in 71 communities (including Pensacola, Panama City and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility and a municipality.

Mississippi Power is engaged in the generation and purchase of electricity and the distribution and sale of such energy within the 23 counties of southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations and one generating and transmitting cooperative.

Savannah Electric is engaged, within a five-county area in eastern Georgia, in the generation and purchase of electricity and the distribution and sale of such electricity at retail.

Through the Southern Company system power pool, the retail operating companies are also engaged in the transmission and sale of wholesale energy.

For information relating to kilowatt-hour sales by classification for the retail operating companies, see MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS of each of the retail operating companies in Item 7 herein. Also, for information relating to the sources of revenues for the Southern Company system, each of the retail operating companies and Southern Power, reference is made to Item 6 herein.

A portion of the area served by the retail operating companies adjoins the area served by TVA and its municipal and cooperative distributors. An Act of Congress limits the distribution of TVA power, unless otherwise authorized by Congress, to specified areas or customers which generally were those served on July 1, 1957.

The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. There are 71 electric cooperative organizations operating in the territory in which the retail operating companies provide electric service at retail or wholesale.

One of these, AEC, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems and other customers in south Alabama and northwest Florida. AEC owns generating units with approximately 1,776 megawatts of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power’s Plant Miller Units 1 and 2. AEC’s facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from AEC to the extent such energy is available. Two of the 14 distributing cooperatives operating in Alabama Power’s service territory obtain a portion of their power requirements directly from Alabama Power.

Four electric cooperative associations, financed by the RUS, operate within Gulf Power’s service area. These cooperatives purchase their full requirements from AEC and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power’s service area and purchases its full requirements from Gulf Power.

Alabama Power and Gulf Power have entered into separate agreements with AEC involving interconnection between their respective systems. The delivery of capacity and energy from AEC to certain distributing cooperatives in the service areas of Alabama Power and Gulf Power is governed by the Southern Company/AEC Network Transmission Service Agreement. The rates for this service to AEC are based on the negotiated agreement on file with the FERC. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for details of Alabama Power’s joint-ownership with AEC of a portion of Plant Miller.

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

There are 43 electric cooperative organizations operating in, or in areas adjoining, territory in the State of Georgia in which Georgia Power provides electric service at retail or wholesale. In January 2005, three of these organizations began obtaining their power from

I-15

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

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

There are 65 municipally-owned electric distribution systems operating in the territory in which the retail operating companies provide electric service at retail or wholesale.

AMEA was organized under an act of the Alabama legislature and is comprised of 11 municipalities. In October 1991, Alabama Power entered into a power sales contract with AMEA entitling AMEA to scheduled amounts of additional capacity (up to a maximum 80 megawatts) for a period of 15 years. Under the terms of the contract, Alabama Power received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements. See Note 6 to the financial statements of Alabama Power under “First Mortgage Bonds” in Item 8 herein for further information on this contract.

Forty-eight municipally-owned electric distribution systems and one county-owned system receive their requirements through MEAG, which was established by a Georgia state statute in 1975. MEAG serves these requirements from self-owned generation facilities, some of which are acquired and jointly-owned with Georgia Power, power purchased from Georgia Power and purchases from other resources. In 1997, a pseudo scheduling and services agreement was implemented between Georgia Power and MEAG. Since 1977, Dalton has filled its requirements from self-owned generation facilities, some of which are acquired and jointly-owned with Georgia Power, and through purchases from Georgia Power pursuant to their partial requirements tariff. Beginning January 1, 2003, Dalton entered into a power supply agreement pursuant to which it will purchase 134 megawatts from Georgia Power for a 15-year term. In addition, another municipally-owned electric distribution system’s full requirements are served under a market-based contract by Georgia Power. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation (formerly OPC’s transmission division), MEAG and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of each. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

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

SCS, acting on behalf of the retail operating companies, also has a contract with SEPA providing for the use of those companies’ facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain United States government hydroelectric projects.

I-16

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

Under and subject to the provisions of its franchises and concessions and the 1973 State Territorial Electric Service Act, Savannah Electric has the full but nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale, Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee Island, Springfield, Thunderbolt and Vernonburg, and in conjunction with a secondary supplier, the Town of Richmond Hill. In addition, Savannah Electric has been assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and Screven Counties by the Georgia PSC. See BUSINESS — “Competition” in Item 1 herein for additional information.

Pursuant to the 1956 Utility Act, the Mississippi PSC issued “Grandfather Certificates” of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 375,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a “Grandfather Certificate,” the utility holding such certificate may, without further certification, extend its lines up to five miles; other extensions within that area by such utility, or by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate which are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.

Competition

The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Act. The Energy Act allowed IPPs to access a utility’s transmission network in order to sell electricity to other utilities.

Alabama Power currently has cogeneration contracts in effect with 11 industrial customers. Under the terms of these contracts, Alabama Power purchases excess generation of such companies. During 2004, Alabama Power purchased approximately 178 million kilowatt-hours from such companies at a cost of $5.2 million.

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

Gulf Power currently has agreements in effect with various industrial, commercial and qualifying facilities pursuant to which Gulf Power purchases “as available” energy from customer-owned generation. During 2004, Gulf Power purchased 31 million kilowatt-hours from such companies for $591,000.

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

I-17

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

During 2004, Savannah Electric purchased energy from six customer-owned generating facilities. Five of the six provide only excess energy to Savannah Electric and are paid Savannah Electric’s avoided energy cost. These five customers make no capacity commitment and are not dispatched by Savannah Electric. Savannah Electric does have a contract for five megawatts of dispatchable capacity and energy with one customer. During 2004, Savannah Electric purchased a total of 34 million kilowatt-hours from the six suppliers at a cost of approximately $1.3 million.

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

The retail operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees as the result of self-generation (as described above) and fuel switching by customers and other factors. See also BUSINESS — “Territory Served by the Utilities” in Item 1 herein for additional information concerning suppliers of electricity operating within or near the areas served at retail by the retail operating companies.

Regulation

State Commissions

The retail operating companies are subject to the jurisdiction of their respective state PSCs, which have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC) and, in the cases of the Georgia PSC and Mississippi PSC, in part, retail service territories. See BUSINESS — “Territory Served by the Utilities” and “Rate Matters” in Item 1 herein for additional information.

Holding Company Act

Southern Company is registered as a holding company under the Holding Company Act, and it and its subsidiary companies are subject to the regulatory provisions of said Act, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, services performed by SCS and Southern Nuclear and the activities of certain of Southern Company’s other subsidiaries.

While various proposals have been introduced in Congress regarding the Holding Company Act, the prospects for legislative reform or repeal are uncertain at this time.

Federal Power Act

The Federal Power Act subjects the retail operating companies, Southern Power and SEGCO to regulation by the FERC as companies engaged in the transmission or sale at wholesale of electric energy in interstate commerce, including regulation of accounting policies and practices.

Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. Among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,662,400 kilowatts and 18 existing Georgia Power generating stations having an aggregate installed capacity of 1,074,696 kilowatts.

In December 2002, Georgia Power filed a relicensing application for the Middle Chattahoochee Project with the FERC. On December 27, 2004, the FERC issued a new 30-year license for the Middle Chattahoochee Project. This project consists of the Goat Rock, Oliver and North Highlands facilities. In 2003, Georgia Power started the relicensing process for the Morgan Falls project and is currently working on developing study plans for the facility with license participants. Alabama Power initiated the relicensing process in 2002 for its seven projects on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan and Bouldin) and the Smith and Bankhead projects on the Warrior River. The FERC licenses for all of these eight projects expire in 2007.

I-18

Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity which began commercial operation in 1995. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

Licenses for all projects, excluding those discussed above, expire in the period 2007-2033 in the case of Alabama Power’s projects and in the period 2005-2039 in the case of Georgia Power’s projects.

Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken.

Atomic Energy Act of 1954

Alabama Power, Georgia Power and Southern Nuclear are subject to the provisions of the Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over the construction and operation of nuclear reactors, particularly with regard to certain public health and safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the NRC to consider the environmental impact of a facility licensed under the Atomic Energy Act of 1954, as amended.

NRC operating licenses currently expire in June 2017 and March 2021 for Plant Farley units 1 and 2, respectively, and in January 2027 and February 2029 for Plant Vogtle units 1 and 2, respectively. In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of units 1 and 2 until 2034 and 2038, respectively. Alabama Power filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years.

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

FERC Matters

See Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, Savannah Electric’s and Southern Power’s, MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and State PSC Matters,” “FERC and Alabama PSC Matters,” “FERC and Georgia PSC Matters,” “FERC and Florida PSC Matters,” “FERC and Mississippi PSC Matters,” “FERC and Georgia PSC Matters” and “FERC Matters” in Item 7 herein for information on matters regarding the FERC.

Environmental Statutes and Regulations

Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for Southern Company. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company and each of the retail operating companies in Item 7 herein for additional information about the Clean Air Act and other environmental issues, including the litigation brought under the New Source Review provisions of the Clean Air Act.

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

I-19

information regarding environmental remediation efforts. Also, see Note 3 to the financial statements of Southern Company, Georgia Power, Gulf Power and Mississippi Power in Item 8 herein under “Environmental Matters — Environmental Remediation,” for information regarding the identification of sites that may require environmental remediation.

The retail operating companies, Southern Power and SEGCO are unable to predict at this time what additional steps they may be required to take as a result of the implementation of existing or future quality control requirements for air, water and hazardous or toxic materials, but such steps could adversely affect system operations and result in substantial additional costs.

The outcome of the matters mentioned above under “Regulation” cannot now be determined, except that these developments may result in delays in obtaining appropriate licenses for generating facilities, increased construction and operating costs or reduced generation, the nature and extent of which, while not determinable at this time, could be substantial.

Rate Matters

Rate Structure

The rates and service regulations of the retail operating companies are uniform for each class of service throughout their respective service areas. Rates for residential electric service are generally of the block type based upon kilowatt-hours used and include minimum charges.

Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers’ rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, the retail operating companies are allowed by their respective PSCs to negotiate the terms and compensation of service to large customers. Such terms and compensation of service, however, are subject to final PSC approval. Alabama Power, Georgia Power, Mississippi Power and Savannah Electric are allowed by state law to recover fuel and net purchased energy costs through fuel cost recovery provisions which are adjusted to reflect increases or decreases in such costs as needed. Gulf Power also recovers from retail customers costs of fuel, net purchased power, energy conservation and environmental compliance through provisions approved by the Florida PSC which are adjusted annually to reflect increases or decreases in such costs. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL in Item 7 and to Note 3 to the financial statements in Item 8 herein for Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric for a discussion of rate matters.

Integrated Resource Planning

Georgia Power and Savannah Electric must file IRPs with the Georgia PSC that specify how each intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC must certify these new resources. Once certified, all prudently incurred constructions costs and purchase power costs will be recoverable through rates.

In July 2001, the Georgia PSC approved Georgia Power’s certification request for approximately 1,800 megawatts of purchased power and 12 megawatts of upgraded hydro generation. This certification request included a seven-year PPA with Southern Power for two gas-fired, combined cycle units at Plant Franklin. The purchase of the full 570 megawatts from the first unit began in 2003 with the purchase of approximately 250 megawatts beginning earlier in June 2002. The purchase of the full 610 megawatts from the second unit began in 2004 with the purchase of approximately 300 megawatts beginning earlier in June 2003. Also, an upgrade of 12 megawatts was approved for the existing Goat Rock hydro units 1 and 2. Additionally, this certification included approval of a 15-year PPA with Southern Power for 615 megawatts of gas-fired combined cycle generation at Plant Harris in Alabama.

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

I-20

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

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

Environmental Cost Recovery Plans

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

The Florida Legislature has adopted legislation for an Environmental Cost Recovery Clause, which allows Gulf Power to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation and a return on invested capital.

This legislation was amended in 2002 to allow recovery of costs incurred as a result of an agreement between Gulf Power and the Florida Department of Environmental Protection for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. See Note 3 to the financial statements of Gulf Power in Item 8 herein under “Environmental Remediation” for additional information.

In 1992, the Mississippi PSC approved Mississippi Power’s Environmental Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to facilitate the Mississippi PSC’s overview of Mississippi Power’s environmental strategy and provides for recovery of costs (including costs of capital associated with environmental projects approved by the Mississippi PSC). Under the ECO Plan, any increase in the annual revenue requirement is limited to two percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the two percent limit into the next year’s revenue requirement. Mississippi Power conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. Mississippi Power recovers such costs under the ECO Plan as they are incurred, as provided for in Mississippi Power’s 1994 ECO Plan order. Mississippi Power filed its 2005 ECO Plan in January 2005, which, if approved as filed, will result in an increase in customer prices. See Note 3 to the financial statements of Mississippi Power under “Environmental Compliance Overview Plan” for additional information.

I-21

Employee Relations

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



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

Total		25,642

* Southern Power has no employees. Southern Power has agreements with SCS and the retail operating companies whereby employee services are rendered at cost.

The retail operating companies have separate agreements with local unions of the IBEW generally covering wages, working conditions and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance and construction employees.

Alabama Power has agreements with the IBEW on a five-year contract extending to August 15, 2009. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2005. Negotiations are expected to begin in early May 2005 for a new agreement which is expected to be in effect for the next three years beginning July 1, 2005.

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

Mississippi Power has an agreement with the IBEW on a four-year contract extending to August 16, 2006.

Savannah Electric has three-year labor agreements with the IBEW and the Office and Professional Employees International Union that expire April 15, 2006 and December 1, 2006, respectively.

Southern Nuclear has agreements with the IBEW on a five-year contract extending to August 15, 2006 for Plant Farley, and a three-year contract extending to June 30, 2005 for Plants Hatch and Vogtle. Upon notice given at least 60 days prior to these dates, negotiations may be initiated with respect to agreement terms to be effective after such dates.

The agreements also subject the terms of the pension plans for the companies discussed above to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.

I-22

Item 2. PROPERTIES

Electric Properties – The Electric Utilities

The retail operating companies, Southern Power and SEGCO, at December 31, 2004, owned and/or operated 34 hydroelectric generating stations, 32 fossil fuel generating stations, three nuclear generating stations and 10 combined cycle/cogeneration stations. The amounts of capacity for each company are shown in the table below.


		Nameplate
Generating Station	Location	Capacity (1)
		(Kilowatts)
FOSSIL STEAM
Gadsden	Gadsden, AL		120,000
Gorgas	Jasper, AL		1,221,250
Barry	Mobile, AL		1,525,000
Greene County	Demopolis, AL		300,000	(2)
Gaston Unit 5	Wilsonville, AL		880,000
Miller	Birmingham, AL		2,532,288	(3)

Alabama Power Total			6,578,538


Bowen	Cartersville, GA		3,160,000
Branch	Milledgeville, GA		1,539,700
Hammond	Rome, GA		800,000
McDonough	Atlanta, GA		490,000
McManus	Brunswick, GA		115,000
Mitchell	Albany, GA		125,000
Scherer	Macon, GA		750,924	(4)
Wansley	Carrollton, GA		925,550	(5)
Yates	Newnan, GA		1,250,000

Georgia Power Total			9,156,174


Crist	Pensacola, FL		1,022,500
Lansing Smith	Panama City, FL		305,000
Scholz	Chattahoochee, FL		80,000
Daniel	Pascagoula, MS		500,000	(6)
Scherer Unit 3	Macon, GA		204,500	(4)

Gulf Power Total			2,112,000


Eaton	Hattiesburg, MS		67,500
Sweatt	Meridian, MS		80,000
Watson	Gulfport, MS		1,012,000
Daniel	Pascagoula, MS		500,000	(6)
Greene County	Demopolis, AL		200,000	(2)

Mississippi Power Total			1,859,500


McIntosh	Effingham County, GA		163,117
Kraft	Port Wentworth, GA		281,136
Riverside	Savannah, GA		79,778

Savannah Electric Total			524,031


Gaston Units 1-4	Wilsonville, AL
SEGCO Total			1,000,000	(7)

Total Fossil Steam			21,230,243


NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total			1,720,000


Hatch	Baxley, GA		899,612	(8)
Vogtle	Augusta, GA		1,060,240	(9)

Georgia Power Total			1,959,852

Total Nuclear Steam			3,679,852


COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total			720,000


Bowen	Cartersville, GA		39,400
Intercession City	Intercession City, FL		47,667	(10)
McDonough	Atlanta, GA		78,800
McIntosh Units 1,2,3,4,7,8	Effingham County, GA		480,000
McManus	Brunswick, GA		481,700
Mitchell	Albany, GA		118,200
Robins	Warner Robins, GA		158,400
Wansley	Carrollton, GA		26,322
Wilson	Augusta, GA		354,100

Georgia Power Total			1,784,589


Lansing Smith Unit A	Panama City, FL		39,400
Pea Ridge Units 1-3	Pea Ridge, FL		15,000

Gulf Power Total			54,400


Chevron Cogenerating Station	Pascagoula, MS		147,292	(11)
Sweatt	Meridian, MS		39,400
Watson	Gulfport, MS		39,360

Mississippi Power Total			226,052


Boulevard	Savannah, GA		59,100
Kraft	Port Wentworth, GA		22,000
McIntosh Units 5&6	Effingham County, GA		160,000

Savannah Electric Total			241,100

I-23


		Nameplate
Generating Station	Location	Capacity
		(Kilowatts)
Dahlberg	Jackson County, GA
Southern Power Total			756,000


Gaston (SEGCO)	Wilsonville, AL		19,680	(7)

Total Combustion Turbines			3,801,821


COGENERATION
Washington County	Washington County, AL		123,428
GE Plastics Project	Burkeville, AL		104,800
Theodore	Theodore, AL		236,418

Alabama Power Total			464,646


COMBINED CYCLE
Barry	Mobile, AL
Alabama Power Total			1,070,424


Smith	Lynn Haven, FL
Gulf Power Total			545,500


Daniel (Leased)	Pascagoula, MS
Mississippi Power Total			1,070,424


Stanton Unit A	Orlando, FL		428,649	(13)
Harris	Autaugaville, AL		1,318,920
Franklin	Smiths, AL		1,198,360
Wansley	Carrollton, GA		1,073,000

Southern Power Total			4,018,929

Total Combined Cycle			6,705,277


HYDROELECTRIC FACILITIES

Weiss	Leesburg, AL		87,750
Henry	Ohatchee, AL		72,900
Logan Martin	Vincent, AL		135,000
Lay	Clanton, AL		177,000
Mitchell	Verbena, AL		170,000
Jordan	Wetumpka, AL		100,000
Bouldin	Wetumpka, AL		225,000
Harris	Wedowee, AL		132,000
Martin	Dadeville, AL		175,000
Yates	Tallassee, AL		47,000
Thurlow	Tallassee, AL		81,000
Lewis Smith	Jasper, AL		157,500
Bankhead	Holt, AL		53,985
Holt	Holt, AL		48,000

Alabama Power Total			1,662,135


Barnett Shoals (Leased)	Athens, GA		2,800
Bartletts Ferry	Columbus, GA		173,000
Goat Rock	Columbus, GA		26,000
Lloyd Shoals	Jackson, GA		14,400
Morgan Falls	Atlanta, GA		16,800
North Highlands	Columbus, GA		29,600
Oliver Dam	Columbus, GA		60,000
Rocky Mountain	Rome, GA		215,256	(12)
Sinclair Dam	Milledgeville, GA		45,000
Tallulah Falls	Clayton, GA		72,000
Terrora	Clayton, GA		16,000
Tugalo	Clayton, GA		45,000
Wallace Dam	Eatonton, GA		321,300
Yonah	Toccoa, GA		22,500
6 Other Plants			18,080

Georgia Power Total			1,077,736

Total Hydroelectric Facilities			2,739,871


Total Generating Capacity			38,621,710

Notes:

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

(2)		Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively.

(3)		Capacity shown is Alabama Power’s portion (91.84%) of total plant capacity.

(4)		Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3.

(5)		Capacity shown is Georgia Power’s portion (53.5%) of total plant capacity.

(6)		Represents 50% of the plant which is owned as tenants in common by Gulf Power and Mississippi Power.

(7)		SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.

(8)		Capacity shown is Georgia Power’s portion (50.1%) of total plant capacity.

(9)		Capacity shown is Georgia Power’s portion (45.7%) of total plant capacity.

(10)		Capacity shown represents 33-1/3% of total plant capacity. Georgia Power owns a 1/3 interest in the unit with 100% use of the unit from June through September. FPC operates the unit.

(11)		Generation is dedicated to a single industrial customer.

(12)		Capacity shown is Georgia Power’s portion (25.4%) of total plant capacity. OPC operates the plant.

(13)		Capacity shown is Southern Power’s portion (65%) of total plant capacity.

		Except as discussed below under “Titles to Property,” the principal plants and other important

I-24

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

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

The all-time maximum demand on the retail operating companies, Southern Power and SEGCO was 34,414,100 kilowatts and occurred on July 14, 2004. This amount excludes demand served by capacity retained by MEAG and Dalton and excludes demand associated with power purchased from OPC and SEPA by its preference customers. The reserve margin for the retail operating companies, Southern Power and SEGCO at that time was 20.2%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands.

Jointly-Owned Facilities

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


			Percentage Ownership
	Total		Alabama						Georgia															Southern
	Capacity		Power			AEC			Power			OPC			MEAG			DALTON			FPC			Power			OUC			FMPA			KUA
	(Megawatts)
Plant Miller Units 1 and 2		1,320		91.8	%		8.2	%		—	%		—	%		—	%		—	%		—	%		—	%		—	%		—	%		—	%
Plant Hatch		1,796		—			—			50.1			30.0			17.7			2.2			—			—			—			—			—
Plant Vogtle		2,320		—			—			45.7			30.0			22.7			1.6			—			—			—			—			—
Plant Scherer Units 1 and 2		1,636		—			—			8.4			60.0			30.2			1.4			—			—			—			—			—
Plant Wansley		1,779		—			—			53.5			30.0			15.1			1.4			—			—			—			—			—
Rocky Mountain		848		—			—			25.4			74.6			—			—			—			—			—			—			—
Intercession City, FL		143		—			—			33.3			—			—			—			66.7			—			—			—			—
Plant Stanton A		660		—			—			—			—			—			—			—			65	%		28	%		3.5	%		3.5	%

Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A.

In addition, Georgia Power has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG’s bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit’s variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC’s disallowances of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power’s Statements of Income in Item 8 herein.

I-25

Titles to Property

The retail operating companies’, Southern Power’s and SEGCO’s interests in the principal plants (other than certain pollution control facilities, one small hydroelectric generating station leased by Georgia Power, combined cycle units at Plant Daniel leased by Mississippi Power and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the liens of applicable mortgage indentures of Alabama Power, Gulf Power, Mississippi Power and Savannah Electric, to second liens pursuant to pollution control bonds of Gulf Power and to excepted encumbrances as defined therein. See Note 6 to the financial statements of Southern Company, Alabama Power, Gulf Power, Mississippi Power and Savannah Electric under “Assets Subject to Lien” and Note 7 to the financial statements of Mississippi Power under “Operating Leases — Plant Daniel Combined Cycle Generating Units” in Item 8 herein for additional information. The retail operating companies own the fee interests in certain of their principal plants as tenants in common. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information. Properties such as electric transmission and distribution lines and steam heating mains are constructed principally on rights-of-way which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements.

Item 3. LEGAL PROCEEDINGS

(1)   United States of America v. Alabama Power
(United States District Court for the Northern District of Alabama)

    United States of America v. Georgia Power and Savannah Electric
(United States District Court for the Northern District of Georgia)

    See “New Source Review Actions” in Note 3 to Southern Company’s and each retail operating company’s financial statements in Item 8 herein for information.

(2)   Cooper et al. v. Georgia Power, Southern Company, SCS and Energy Solutions
(Superior Court of Fulton County, Georgia)

    See “Race Discrimination Litigation” in Note 3 to Southern Company and Georgia Power financial statements in Item 8 herein for information.

(3)   Environmental Remediation

    See “Environmental Remediation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s and Mississippi Power’s financial statements in Item 8 herein for information related to environmental remediation.

(4)   In re: Mirant Corporation, et al.
(U.S. Bankruptcy Court for the Northern District of Texas)

    See “Mirant Bankruptcy” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.

I-26

(5)   In re: Mirant Corporation Securities Litigation
(United States District Court for the Northern District of Georgia)

    See “Mirant Securities Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.

(6)   In re: Mirant Corporation ERISA Litigation
(United States District Court for the Northern District of Georgia)

    See “Southern Company Employee Savings Plan Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.

(7)   Sierra Club, et al. v. Georgia Power
(United States District Court for the Northern District of Georgia)

    See “Plant Wansley Environmental Litigation” in Note 3 to Southern Company’s and Georgia Power’s financial statements in Item 8 herein for information.

(8)   Right of Way Litigation

    See “Right of Way Litigation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s and Savannah Electric’s financial statements in Item 8 herein for information.

(9)   Jerry A. Carter v. Gulf Power

    See “Personal Injury Litigation” in Note 3 to Gulf Power’s financial statements in Item 8 herein for information.

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

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

None.

I-27

EXECUTIVE OFFICERS OF SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2004.

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

Dwight H. Evans
Executive Vice President
Age 56
Elected in 2001. Executive Vice President since May 2001. Previously served as President and Chief Executive Officer of Mississippi Power from March 1995 to May 2001.

Thomas A. Fanning
Executive Vice President, Chief Financial Officer and Treasurer
Age 47
Elected in 2003. Executive Vice President, Chief Financial Officer and Treasurer since April 2003. Previously served as President, Chief Executive Officer and Director of Gulf Power from 2002 to April 2003; and Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002.

Michael D. Garrett
Executive Vice President
Age 55
Elected in 2004. Executive Vice President since January 1, 2004. He also serves as President and Director of Georgia Power since January 1, 2004 and Chief Executive Officer of Georgia Power since April 2004. Previously served as President, Chief Executive Officer and Director of Mississippi Power from 2001 to 2003; Executive Vice President — Customer Service of Alabama Power from January 2000 to May 2001; and Executive Vice President of External Affairs of Alabama Power from March 1998 to January 2000.

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

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

Charles D. McCrary
Executive Vice President
Age 53
Elected in 1998. Executive Vice President of Southern Company since February 2002; President and Chief Executive Officer of Alabama Power since October 2001. Previously served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001; and Vice President of Southern Company from February 1998 to April 2001.

W. Paul Bowers (1)
Executive Vice President of SCS and President and Chief Executive Officer of Southern Power.
Age 48
Elected in 2001. Executive Vice President of SCS and President and Chief Executive Officer of Southern Power since May 2001. Previously served as Senior Vice President and Chief Marketing Officer of Southern Company from March 2000 to May 2001; and President and Chief Executive Officer of Western Power Distribution and Southwestern Electricity plc, a subsidiary of Mirant located in Bristol, England, from December 1998 to 2000.

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

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

I-28

EXECUTIVE OFFICERS OF ALABAMA POWER

(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)
The ages of the officers set forth below are as of December 31, 2004.

Charles D. McCrary
President, Chief Executive Officer and Director
Age 53
Elected in 2001. President, Chief Executive Officer and Director since October 2001; Executive Vice President of Southern Company since February 2002. Previously served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001; and Vice President of Southern Company from February 1998 to April 2001.

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

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

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

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

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

I-30

EXECUTIVE OFFICERS OF GEORGIA POWER

(Identification of executive officers of Georgia Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)
The ages of the officers set forth below are as of December 31, 2004.

Michael D. Garrett
Chief Executive Officer, President and Director
Age 55
Elected in 2003. Chief Executive Officer since April 2004; President and Director since January 1, 2004. Previously served as President, Chief Executive Officer and Director of Mississippi Power from 2001 to 2003; Executive Vice President — Customer Service of Alabama Power from January 2000 to May 2001; and Executive Vice President of External Affairs of Alabama Power from March 1998 to January 2000.

William C. Archer, III
Executive Vice President
Age 56
Elected in 1995. Executive Vice President of External Affairs since 1995.

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

C. B. Harreld (1)
Executive Vice President, Chief Financial Officer, Treasurer and Assistant Secretary
Age 60
Elected in 2003. Executive Vice President, Chief Financial Officer and Treasurer since 2003. Previously served as Senior Vice President of Finance, SCS from 2002 to 2003; Chief Financial Officer and Comptroller of Southern Company Generation and Energy Marketing from 2001 to 2002; Chief Financial Officer of Mirant — Europe from 2000 to 2001; and Vice President and Controller, Southern Energy, Inc. from 1999 to 2000.

Cliff S. Thrasher (2)
Executive Vice President, Chief Financial Officer and Treasurer
Age 55
Elected in 2005. Currently serves as Senior Vice President, Comptroller and Chief Financial Officer of Southern Power since November 2002 and Vice President of SCS since June 2002. Previously served as Vice President, Comptroller and Chief Financial Officer of Southern Power from June 2002 to November 2002; and Vice President, Comptroller and Chief Accounting Officer of Georgia Power from September 1995 to June 2002.

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

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

Douglas E. Jones
Senior Vice President
Age 46
Elected in 2005. Senior Vice President since January 10, 2005. Previously served as Executive Vice President of Southern Power from January 2004 to January 2005; Senior Vice President, Southern Company Energy Marketing from December 2001 to January 2004; and Vice President, Southern Company Wholesale Energy from December 1998 to 2001.

I-31

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

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

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

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

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

The officers of Georgia Power were elected for a term running from the last annual meeting of the directors (May 19, 2004) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Jones whose election was effective on January 10, 2005, and Mr. Thrasher whose election will be effective on March 17, 2005.

I-32

EXECUTIVE OFFICERS OF GULF POWER

(Identification of executive officers of Gulf Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)
The ages of the officers set forth below are as of December 31, 2004.

Susan N. Story
President, Chief Executive Officer and Director
Age 44
Elected in 2003. President, Chief Executive Officer and Director since 2003. Previously served as Executive Vice President of Engineering and Construction Services at Southern Company Generation and Energy Marketing from 2001 to 2003; Vice President of Procurement and Materials at SCS from 2000 to 2001; and Vice President of Corporate Services and Corporate Real Estate at Alabama Power from 1997 to 2000.

Francis M. Fisher, Jr.
Vice President
Age 56
Elected in 1989. Vice President of Customer Operations since 1996.

P. Bernard Jacob
Vice President
Age 50
Elected in 2003. Vice President of External Affairs and Corporate Services since 2003. Previously served as Director of Information Resources Security and Program Management at SCS from 2002 to 2003; and Manager of Telecommunications Strategy at SCS from 1998 to 2002.

Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
Age 51
Elected in 2000. Vice President, Chief Financial Officer and Comptroller since July 27, 2001. Previously served as Comptroller and Chief Financial Officer from 2000 to 2001 and Comptroller from 1992 to 2000.

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

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

I-33

EXECUTIVE OFFICERS OF MISSISSIPPI POWER

(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2004.

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

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

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

Bobby J. Kerley
Vice President
Age 51
Elected in 2003. Vice President of Customer Services and Retail Marketing since December 2003. Previously served at Alabama Power as Division Vice President — Southeast Division Office from April 2001 to December 2003; Division Manager — Operations, Birmingham Division Office from January 2001 to April 2001; and Transmission Lines Manager, Corporate Headquarters from March 1997 to January 2001.

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

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

Gene L. Ussery, Jr. (3)
Vice President
Age 55
Elected in 2000. Vice President of Power Generation and Delivery since September 2000; Vice President of Power Generation at Gulf Power since May 2002. Previously served as Northern Cluster Manager at Georgia Power for Plants Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000; and Manager of Plant Bowen at Georgia Power from 1997 to 2000.

(1) Mr. Southern was elected Senior Vice President, Comptroller and Chief Financial Officer of Southern Power, effective March 17, 2005, and has resigned from Mississippi Power effective as of such date.

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

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

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

I-34

PART II

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

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

(a) The common stock of Southern Company is listed and traded on the New York Stock Exchange. The stock is also traded on regional exchanges across the United States. High and low stock prices, per the New York Stock Exchange Composite Tape, during each quarter for the past two years were as follows:



	High		Low
2004
First Quarter	$	30.87	$	29.10
Second Quarter		30.59		27.86
Third Quarter		30.65		28.86
Fourth Quarter		33.92		29.95
2003
First Quarter	$	30.81	$	27.71
Second Quarter		31.81		27.94
Third Quarter		30.53		27.76
Fourth Quarter		30.40		28.65

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

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

125,975

Each of the other registrants have one common stockholder, Southern Company.

(c) Dividends on each registrant’s common stock are payable at the discretion of their respective board of directors. The dividends on common stock declared by Southern Company and the retail operating companies to their stockholder(s) for the past two years were as follows:



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

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

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

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

II-1

Power, Georgia Power and Southern Power) is restricted in accordance with their respective first mortgage bond indenture. See Note 8 of Southern Company and Note 6 of Gulf Power, Mississippi Power and Savannah Electric to the financial statements in Item 8 herein under “Common Stock Dividend Restrictions,” “Dividend Restrictions,” “Dividend Restrictions” and “Common Stock Dividend Restrictions,” respectively, for additional information regarding these restrictions. The amounts of earnings retained in the business and the amounts restricted against the payment of cash dividends on common stock at December 31, 2004 were as follows:



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

Item 6. SELECTED FINANCIAL DATA

Item 6. SELECTED FINANCIAL DATA

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

II-2

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2004 FINANCIAL STATEMENTS


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

II-3


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

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

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

None.

II-4

Item 9A. CONTROLS AND PROCEDURES

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls And Procedures.

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

As of the end of the period covered by this annual report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to their company (including its consolidated subsidiaries, if any) required to be included in periodic filings with the SEC.

Savannah Electric

As of the end of the period covered by this annual report, Savannah Electric conducted an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive and Chief Financial Officer concluded that the disclosure controls and procedures were not effective in alerting them in a timely manner to material information relating to Savannah Electric required to be included in periodic filings with the SEC, because of an internal control weakness described below.

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

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

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

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

II-5

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.

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

There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2004 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s or Southern Power’s internal control over financial reporting.

Savannah Electric

There have been no changes in Savannah Electric’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2004 that have materially affected or are reasonably likely to materially affect Savannah Electric’s internal control over financial reporting. However, as described above in this Item 9A under Savannah Electric’s “Disclosure Controls and Procedures,” Savannah Electric made changes to its process and controls related to estimating unbilled revenues during the first quarter of 2005.

Item 9B. OTHER INFORMATION

Item 9B. OTHER INFORMATION

None.

II-6

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

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

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

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

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

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

February 28, 2005

II-8

Internal Control over Financial Reporting

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Southern Company

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

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

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

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

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

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

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

II-9

Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Southern Company

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the consolidated financial statements (pages II-35 to II-70) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

II-10

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

OVERVIEW

Business Activities

Southern Company’s primary business is electricity sales in the Southeast by the retail operating companies — Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric — and Southern Power. Southern Power is an electric wholesale generation subsidiary with market-based rate authority.

Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. These factors include the retail operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards. In 2004, Alabama Power, Georgia Power, and Mississippi Power each completed retail rate proceedings that should help provide future earnings stability. These regulatory actions will also enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and to continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.

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

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

Key Performance Indicators

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


Key	2004	2004
Performance	Target	Actual
Indicator	Performance	Performance
Customer	Top quartile	Top quartile
Satisfaction	in national
	and regional
	surveys

Peak Season EFOR	3.00% or less	1.22%

ROE	14.5%	15.4%

EPS	$1.94 - $1.99	$2.07

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

II-11

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

Earnings

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

Dividends

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

RESULTS OF OPERATIONS

Electricity Businesses

Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed income statement for the electricity business is as follows:


			Increase (Decrease)
	Amount		from Prior Year
	2004		2004			2003			2002
	(in millions)
Electric operating revenues	$	11,465	$	718		$	541		$	291

Fuel		3,395		397			212			209
Purchased power		643		170			24			(269	)
Other operation and maintenance		3,008		150			106			253
Depreciation and amortization		908		(64	)		(16	)		(155	)
Taxes other than income taxes		624		40			29			22

Total electric operating expenses		8,578		693			355			60

Operating income		2,887		25			186			231
Other income, net		23		21			20			(41	)
Interest expenses		614		19			10			(24	)
Income taxes		875		30			68			75

Net income	$	1,421	$	(3	)	$	128		$	139

Revenues

Details of electric operating revenues are as follows:


	2004			2003			2002
	(in millions)
Retail — prior year	$	8,875		$	8,728		$	8,440
Change in —
Base rates		41			75			33
Sales growth		216			104			98
Weather		48			(135	)		158
Fuel and other cost recovery clauses		552			103			(1	)

Retail — current year		9,732			8,875			8,728

Sales for resale —
Within service area		504			444			443
Outside service area		837			914			725

Total sales for resale		1,341			1,358			1,168

Other electric operating revenues		392			514			310

Electric operating revenues	$	11,465		$	10,747		$	10,206

Percent change		6.7	%		5.3	%		2.9	%

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

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

Revenues from energy sales for resale outside the service area decreased $77 million in 2004 and increased $189 million in 2003. In general, sales for resale outside the service area can be significantly influenced by weather, which affects both customer demand and generating availability for these types of sales. Neighboring utilities that depend heavily on gas-

II-12

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

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

Southern Company’s average wholesale contract now extends more than 13 years. As a result, the Company has significantly reduced its remarketing risk until the middle of the next decade. Under unit power sales contracts, principally sales to Florida utilities, capacity revenues reflect the recovery of fixed costs and a return on investment, and energy is generally sold at variable cost. The capacity and energy components of the unit power contracts and other long-term contracts were as follows:


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

Total	$	837	$	914	$	725

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

Energy Sales

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


(billions of	Amount		Percent Change
kilowatt-hours)	2004		2004			2003			2002

Residential		49.7		3.9	%		(1.9	)%		9.5	%
Commercial		50.0		3.4			0.3			2.8
Industrial		56.4		3.6			1.0			1.8
Other		1.0		0.8			(0.2	)		2.3

Total retail		157.1		3.6			(0.2	)		4.5
Sales for resale —
Within service area		11.4		6.6			(1.3	)		15.6
Outside service area		23.9		(20.1	)		37.4			1.5

Total		192.4		0.1			4.2			4.7

Energy sales in 2004 were strong across all retail customer classes as a result of an improved economy in the Southeast and customer growth of 1.5 percent. Residential energy sales in 2003 reflected a decrease in customer demand as a result of very mild weather partially offset by customer growth of 1.6 percent. In 2003, commercial sales continued to show steady growth while industrial sales increased somewhat over the depressed results of recent years. In 2002, the rate of growth in total retail energy sales was very strong. Residential energy sales reflected an increase as a result of hotter-than-normal summer weather and a 1.6 percent increase in customers. Energy sales to retail customers are projected to increase at an average annual rate of 1.88 percent during the period 2005 through 2010.

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

Electric Operating Expenses

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

II-13

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

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

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

In 2002, electric operating expenses were $7.5 billion, an increase of $60 million over 2001 expenses. Production costs exceeded 2001 costs by $87 million as a result of increased sales. Non-production operation and maintenance costs also increased in 2002 by $106 million due to additional administrative and general expenses of $56 million and transmission and distribution expenses of $37 million. Taxes other than income taxes increased $22 million in 2002 due to higher property taxes related to commercial operation of new generating plants. Depreciation and amortization declined by $155 million in 2002 primarily as a result of Georgia Power’s 2001 rate order to reverse and amortize over three years $333 million that had been previously expensed related to accelerated depreciation under a previous rate order. This amortization reduced depreciation expense in 2002 by $111 million.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The amount and sources of generation, the average cost of fuel per net kilowatt-hour generated, and the average cost of purchased power were as follows:


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

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

Fuel and purchased power expenses were $3.5 billion in 2003, an increase of $236 million or 7.3 percent above the prior year costs. This increase was primarily attributed to higher average unit fuel cost and increased customer demand. The additional demand was met by generating 6 billion and purchasing 1.6 billion more kilowatt-hours than in 2002.

In 2002, fuel and purchased power expenses were $3.2 billion, a decrease of $60 million or 1.8 percent below the prior year costs. An additional 8.9

II-14

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

billion kilowatt-hours were generated in 2002, at a slightly higher average cost; however, this lowered requirements to purchase more expensive electricity from other utilities.

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

Electric Other Income and (Expense)

Total interest charges and other financing costs increased by $19 million in 2004 as a result of a lower percentage of interest costs capitalized as Southern Power projects reached completion in 2003. This increase was partially offset by the refinancing of higher cost debt at the retail operating companies in 2003. Total interest charges and other financing costs declined by $24 million in 2002 as a result of lower interest rates on short-term debt and continued refinancing of higher-cost long-term securities.

Other Business Activities

Southern Company’s other business activities include the parent company — which does not allocate operating expenses to business units — investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. These businesses are classified in general categories and may comprise one or more of the following subsidiaries. Southern Company Holdings invests in various energy-related projects, including synthetic fuels and leveraged lease projects that receive tax benefits, which contribute significantly to the economic results of these investments; SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast; Southern Telecom provides fiber optics services in the Southeast; and Southern Company GAS is a retail gas marketer serving customers in the State of Georgia.

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


				Increase (Decrease)
	Amount			from Prior Year
	2004			2004			2003			2002
	(in millions)
Operating revenues	$	437		$	(2	)	$	131		$	68

Operation and maintenance		447			8			98			79
Depreciation and amortization		47			(8	)		(4	)		29
Taxes other than income taxes		3			1			—			—

Total operating expenses		497			1			94			108

Operating income		(60	)		(3	)		37			(40	)
Equity in losses of unconsolidated subsidiaries		(97	)		(2	)		(3	)		(31	)
Leveraged lease income		70			4			8			(1	)
Other income, net		(7	)		(14	)		7			(10	)
Interest expenses		83			(21	)		5			(36	)
Income taxes		(288	)		(55	)		16			(105	)

Net income	$	111		$	61		$	28		$	59

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

II-15

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

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

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

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

The increases in equity in losses of unconsolidated subsidiaries in 2002 reflect the results of additional investments in synthetic fuel partnerships that produce operating losses. These partnerships also claim federal income tax credits that offset these operating losses and make the projects profitable. These credits totaled $146 million in 2004, $120 million in 2003, and $108 million in 2002. Additionally in 2004, a $37 million reserve related to these tax credits was reversed following the settlement of an Internal Revenue Service (IRS) audit. See FUTURE EARNINGS POTENTIAL — “Income Tax Matters — Synthetic Fuel Tax Credits” herein and Note 3 to the financial statements under “Income Tax Matters — Synthetic Fuel Tax Credits” for additional information.

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

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

Effects of Inflation

The retail operating companies and Southern Power are subject to rate regulation and are party to long-term contracts, respectively, that are based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the retail operating companies’ approved electric rates.

FUTURE EARNINGS POTENTIAL

General

The retail operating companies operate as vertically integrated companies providing electricity to customers within their service areas in the southeastern United States. Prices for electricity provided to retail customers are set by state public service commissions (PSC) under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on ROE. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

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

II-16

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

Company’s primary business of selling electricity. These factors include the retail operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area.

Since 2001, merchant energy companies and traditional electric utilities with significant energy marketing and trading activities have come under severe financial pressures. Many of these companies have completely exited or drastically reduced all energy marketing and trading activities and sold foreign and domestic electric infrastructure assets. Southern Company has not experienced any material adverse financial impact regarding its limited energy trading operations and recent generating capacity additions. In general, Southern Company has constructed new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities.

To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of Southern Company.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and added allegations regarding two additional generating facilities owned by Alabama Power. The EPA filed a separate action against Alabama Power after it was dismissed from the original action. As of the date of this report, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The actions against Alabama Power, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final resolution of that appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions” for additional information.

Southern Company believes that the retail operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly

II-17

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

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

In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the individual states to apply to facilities in the Southern Company system. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

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

Plant Wansley Environmental Litigation

On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of Georgia Power in part and the plaintiffs in part. Georgia Power has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. See Note 3 to the financial statements under “Environmental Matters — Plant Wansley Environmental Litigation” for additional information. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

Environmental Statutes and Regulations

Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

II-18

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

nitrogen oxide emissions and resulted in total construction expenditures of approximately $400 million through 2000. Some of these previous expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Atlanta, Georgia, and Birmingham, Alabama. The states of Alabama and Georgia adopted regulations that required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Seven generating plants in the Atlanta area and two plants in the Birmingham area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled approximately $1.1 billion through 2004 with an additional $500 million committed through 2007 for these two states. These expenditures include costs associated with the regional nitrogen oxide reduction rules discussed below. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for information regarding Alabama Power’s recovery of costs associated with environmental laws and regulations.

In addition, in 2002, Gulf Power entered into an agreement with the State of Florida to install additional controls on certain units and to retire three older units at a plant near Pensacola to help ensure attainment of the ozone standard in the area. The conditions of the agreement will be fully implemented in 2006 at a cost of approximately $138 million, of which $44 million remains to be spent. Gulf Power’s costs have been approved under its environmental cost recovery clause. See Note 1 to the financial statements under “Environmental Cost Recovery” for additional information.

To help attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Alabama and Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. Affected sources, including five of the Company’s coal-fired plants in Alabama, were required to comply with the reduction requirements by May 31, 2004. However, as a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements could be applied in Georgia. In April 2004, the EPA published final regional nitrogen oxide reduction rules applicable to Georgia, specifying a May 1, 2007 compliance date. However, in October 2004, the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the nitrogen oxide reduction rules will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of Georgia’s state implementation plan and cannot be determined at this time.

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

In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA’s implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court’s concerns. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. Areas within the Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham, Macon (Georgia), and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005 and that areas classified as “severe” nonattainment areas under the one-hour standard, such as Atlanta, will not be required to impose emissions fees if those areas fail to come into attainment with the one-hour standard. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas

II-19

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

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

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

In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases — in 2010 and 2015. The EPA currently plans to finalize this rule in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.

The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs cannot be determined at this time.

Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA’s Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. The Company has a number of plants that could be subject to these rules. The EPA’s Regional Haze program calls for states to submit implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states, and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations — a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities. The regulations are scheduled to be finalized by March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

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

II-20

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

Under the Clean Water Act, the EPA has been developing new rules aimed at reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. In July 2004, the EPA published final rules that will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual limits established by the regulatory agencies.

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

Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act, and the Endangered Species Act. Compliance with possible additional federal or state legislation or regulations related to global climate change or other environmental and health concerns could also significantly affect Southern Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of Southern Company’s operations. The full impact of any such changes cannot, however, be determined at this time.

Global Climate Issues

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

Environmental Remediation Reserves

Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the retail operating companies could incur substantial costs to clean up properties. The retail operating companies conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The retail operating companies may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters — Environmental Remediation” for additional information.

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

II-21

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

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

FERC and State PSC Matters

Transmission

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

Generation Interconnection Agreements

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

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities’ applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

II-22

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

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

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

Georgia Power Retail Rate Case

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

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

Alabama Power Environmental Rate Filing

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

Mississippi Power Retail Rate Filing

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

II-23

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

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

Plant McIntosh Construction Project

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

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

Retail Fuel Cost Recovery

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

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

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

II-24

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

Storm Damage Cost Recovery

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

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

At Alabama Power, operation and maintenance expenses associated with repairing the damage to its facilities and restoring service to customers as a result of Hurricane Ivan were $57.8 million for 2004. The balance in Alabama Power’s natural disaster reserve prior to the storm was $14.6 million. In October 2004, Alabama Power received approval from the Alabama PSC to defer the negative balance for recovery in future periods. Alabama Power is allowed to accrue $250,000 per month until a maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2004, Alabama Power accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004, the negative balance totaled $37.7 million and is reflected in the balance sheet as a regulatory asset.

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

Income Tax Matters

Synthetic Fuel Tax Credits

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

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

Leveraged Lease Transactions

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

II-25

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

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

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

American Jobs Creation Act of 2004

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

Other Matters

Other Construction Projects

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

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

Mirant Related Matters

On July 14, 2003, Mirant Corporation (Mirant) filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code with the U.S. Bankruptcy Court. Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 to the financial statements under “Guarantees” and with various lawsuits discussed in Note 3 to the financial statements under “Mirant Related Matters.”

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

II-26

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

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

Other

In accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, Southern Company recorded non-cash pension income, before tax, of approximately $44 million, $99 million, and $117 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. The decline in pension income is expected to continue and become an expense as early as 2006. Postretirement benefit costs for Southern Company were $106 million, $101 million, and $99 million in 2004, 2003, and 2002, respectively, and are expected to continue to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. For the retail operating companies, pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax related issues that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.

Electric Utility Regulation

Southern Company’s retail operating companies, which comprise approximately 85 percent of Southern Company’s total earnings, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the retail operating companies are permitted to charge customers based on allowable costs. As a result, the retail operating companies apply FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the retail operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

Southern Company and its subsidiaries are subject to a number of federal and state laws and regulations, as well as other factors and conditions that

II-27

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

potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial statements. These events or conditions include the following:

•   Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.

•   Changes in existing income tax regulations or changes in IRS interpretations of existing regulations.

•   Identification of additional sites that require environmental remediation or the filing of other complaints in which Southern Company or its subsidiaries may be asserted to be a potentially responsible party.

•   Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant.

•   Resolution or progression of existing matters through the legislative process, the court systems, the IRS, or the EPA.

Unbilled Revenues

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

New Accounting Standards

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

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

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

II-28

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

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

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

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

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

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and externally through the issuance of debt, preferred securities, preferred stock, and equity. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2005 — as well as in subsequent years — will be contingent on Southern Company’s investment opportunities. The Company does not currently anticipate any equity offerings in 2005 and is currently developing a program to repurchase shares to offset issuances under the Company’s stock compensation plans.

The retail operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. In recent years, financings primarily have utilized unsecured debt and preferred securities. However, the type and timing of any financings — if needed — will depend on market conditions and regulatory approval. The issuance of securities by Southern Company and its subsidiaries is generally subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA), and, generally, for the retail operating companies, the appropriate state PSC. Additionally, with respect to the public offering of securities, Southern Company and its subsidiaries must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

II-29

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

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

Southern Company and each retail operating company obtains financing separately without credit support from any affiliate. Currently, Southern Company provides limited credit support to Southern Power. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company. In accordance with the PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has various internal and external sources of liquidity. At December 31, 2004, Southern Company and its subsidiaries had approximately $373 million of cash and cash equivalents and $3.2 billion of unused credit arrangements with banks, as described below. In addition, Southern Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.

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

Financing Activities

During 2004, Southern Company and its subsidiaries issued $2.1 billion of long-term debt, including long-term debt payable to affiliated trusts, and $175 million of preferred stock. In addition, Southern Company issued 7 million new shares of common stock through the Company’s stock plans and realized proceeds of $124 million. The security issuances were primarily used to redeem $1.5 billion of long-term debt. The remainder was used to reduce short-term debt, provide capital contributions to subsidiaries, and fund Southern Company’s ongoing construction program.

Subsequent to December 31, 2004, Georgia Power refinanced $250 million of maturing long-term debt.

Off-Balance Sheet Financing Arrangements

In May 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel. The facility cost approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50 percent of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease also provides for a residual value guarantee — approximately 73 percent of the acquisition cost — by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the assets. See Note 7 to the financial statements under “Operating Leases” for additional information.

Credit Rating Risk

II-30

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

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

Market Price Risk

Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on $1.8 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2005 was 2.6 percent. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $20.1 million at January 1, 2005. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Due to cost-based rate regulations, the retail operating companies have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. To mitigate residual risks relative to movements in electricity prices, the retail operating companies and Southern Power enter into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The retail operating companies have implemented fuel-hedging programs at the instruction of their respective state PSCs. Southern Company GAS also has in place a risk management program to substantially mitigate its exposure to price volatility for its natural gas purchases.

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


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

Contracts end of year	$	10.5		$	15.8

(a) Current period changes also include the changes in fair value of new contracts entered into during the period.


Source of 2004 Year-End Valuation Prices
	Total		Maturity
	Fair Value		2005		2006-2007
	(in millions)
Actively quoted	$	9.4	$	6.3	$	3.1
External sources		1.1		1.1		—
Models and other methods		—		—		—

Contracts end of year	$	10.5	$	7.4	$	3.1

Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the retail operating companies’ fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the retail operating companies’ fuel cost recovery clauses. In addition, unrealized gains and losses on energy-related derivatives used by Southern Power and Southern Company GAS to hedge anticipated purchases and sales are deferred in other comprehensive income. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

II-31

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


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

Total fair value	$	10.5

Unrealized pre-tax gains and losses recognized in income were not material for any year presented. Southern Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. Southern Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of Southern Company is currently estimated to be $2.2 billion for 2005, $2.5 billion for 2006, and $3.2 billion for 2007. Environmental expenditures included in these amounts are $452 million, $615 million, and $896 million for 2005, 2006, and 2007, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials, and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Southern Company has approximately 1,200 megawatts of new generating capacity scheduled to be placed in service by Georgia Power and Savannah Electric in June 2005. In addition, capital improvements, including those needed to meet the environmental standards previously discussed for the retail operating companies’ generation, transmission, and distribution facilities, are ongoing.

As a result of requirements by the Nuclear Regulatory Commission, Alabama Power and Georgia Power have established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also, as discussed in Note 1 to the financial statements under “Fuel Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants, to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.

In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the retail operating companies’ respective regulatory commissions.

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

II-32

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

Contractual Obligations


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

Total	$	8,183	$	15,612	$	4,576	$	23,056	$	51,427

(a)   All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2005, as reflected in the statements of capitalization.

(b)   Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c)   Southern Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $3.3 billion, $3.2 billion, and $3.1 billion, respectively.

(d)   Southern Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.

(e)   Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2004.

(f)   Southern Company forecasts postretirement trust contributions over a three-year period. No contributions related to Southern Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

II-33

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

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, retail sales growth, storm damage cost recovery, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•   current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, IRS audits, and Mirant related matters;

•   the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;

•   variations in demand for electricity and gas, including those relating to weather, the general economy and population, and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

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

•   advances in technology;

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

•   the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

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

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

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

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

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

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

•   the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;

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

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

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

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

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

II-34

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



	2004			2003			2002
	(in millions)
Operating Revenues:
Retail sales	$	9,732		$	8,875		$	8,728
Sales for resale		1,341			1,358			1,168
Other electric revenues		392			514			310
Other revenues		437			439			308

Total operating revenues		11,902			11,186			10,514

Operating Expenses:
Fuel		3,521			3,121			2,831
Purchased power		643			473			449
Other operations		2,302			2,237			2,083
Maintenance		1,027			937			965
Depreciation and amortization		955			1,027			1,047
Taxes other than income taxes		627			586			557

Total operating expenses		9,075			8,381			7,932

Operating Income		2,827			2,805			2,582
Other Income and (Expense):
Allowance for equity funds used during construction		47			25			22
Interest income		27			36			22
Equity in losses of unconsolidated subsidiaries		(95	)		(94	)		(91	)
Leveraged lease income		70			66			58
Interest expense, net of amounts capitalized		(540	)		(527	)		(492	)
Interest expense to affiliate trusts		(100	)		—			—
Distributions on mandatorily redeemable preferred securities		(27	)		(151	)		(175	)
Preferred dividends of subsidiaries		(30	)		(21	)		(17	)
Other income (expense), net		(60	)		(53	)		(63	)

Total other income and (expense)		(708	)		(719	)		(736	)

Earnings Before Income Taxes		2,119			2,086			1,846
Income taxes		587			612			528

Consolidated Net Income	$	1,532		$	1,474		$	1,318

Common Stock Data:
Earnings per share -
Basic	$	2.07		$	2.03		$	1.86
Diluted		2.06			2.02			1.85

Average number of shares of common stock outstanding — (in millions)
Basic		739			727			708
Diluted		743			732			714

Cash dividends paid per share of common stock	$	1.415		$	1.385		$	1.355

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

II-35

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



	2004			2003			2002

	(in millions)
Operating Activities:
Consolidated net income	$	1,532		$	1,474		$	1,318
Adjustments to reconcile consolidated net income to net cash provided from operating activities -
Depreciation and amortization		1,178			1,221			1,185
Deferred income taxes and investment tax credits		559			429			172
Plant Daniel capacity		(17	)		60			—
Allowance for equity funds used during construction		(47	)		(25	)		(22	)
Equity in losses of unconsolidated subsidiaries		95			94			91
Leveraged lease income		(70	)		(66	)		(58	)
Pension, postretirement, and other employee benefits		—			(25	)		(78	)
Tax benefit of stock options		31			30			23
Hedge settlements		(10	)		(116	)		(16	)
Other, net		(21	)		2			14
Changes in certain current assets and liabilities -
Receivables, net		(369	)		6			(35	)
Fossil fuel stock		(8	)		(17	)		105
Materials and supplies		(31	)		(12	)		8
Other current assets		14			27			(58	)
Accounts payable		29			(88	)		105
Accrued taxes		(109	)		19			(49	)
Accrued compensation		(16	)		(11	)		41
Other current liabilities		(48	)		69			107

Net cash provided from operating activities		2,692			3,071			2,853

Investing Activities:
Gross property additions		(2,110	)		(2,014	)		(2,728	)
Investment in unconsolidated subsidiaries		(97	)		(94	)		(90	)
Cost of removal net of salvage		(75	)		(80	)		(109	)
Construction receivables/payables, net		25			(34	)		(17	)
Other		5			27			(24	)

Net cash used for investing activities		(2,252	)		(2,195	)		(2,968	)

Financing Activities:
Decrease in notes payable, net		(141	)		(366	)		(968	)
Proceeds —
Long-term debt		1,861			3,494			2,914
Mandatorily redeemable preferred securities		200			—			1,315
Preferred stock		175			125			—
Common stock		124			470			428
Redemptions —
Long-term debt		(1,245	)		(3,009	)		(1,370	)
Mandatorily redeemable preferred securities		(240	)		(480	)		(1,171	)
Preferred stock		(28	)		—			(70	)
Payment of common stock dividends		(1,045	)		(1,004	)		(958	)
Other		(39	)		(68	)		(86	)

Net cash provided from (used for) financing activities		(378	)		(838	)		34

Net Change in Cash and Cash Equivalents		62			38			(81	)
Cash and Cash Equivalents at Beginning of Year		311			273			354

Cash and Cash Equivalents at End of Year	$	373		$	311		$	273

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

II-36

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



Assets	2004			2003

	(in millions)

Current Assets:
Cash and cash equivalents	$	373		$	311
Receivables -
Customer accounts receivable		755			680
Unbilled revenues		304			275
Under recovered regulatory clause revenues		532			204
Other accounts and notes receivable		320			338
Accumulated provision for uncollectible accounts		(46	)		(30	)
Fossil fuel stock, at average cost		325			316
Vacation pay		105			97
Materials and supplies, at average cost		602			570
Prepaid expenses		126			269
Other		67			30

Total current assets		3,463			3,060

Property, Plant, and Equipment:
In service		41,437			40,339
Less accumulated depreciation		14,951			14,312

		26,486			26,027
Nuclear fuel, at amortized cost		218			223
Construction work in progress		1,657			1,275

Total property, plant, and equipment		28,361			27,525

Other Property and Investments:
Nuclear decommissioning trusts, at fair value		905			808
Leveraged leases		976			838
Other		392			280

Total other property and investments		2,273			1,926

Deferred Charges and Other Assets:
Deferred charges related to income taxes		864			874
Prepaid pension costs		986			911
Unamortized debt issuance expense		153			152
Unamortized loss on reacquired debt		323			326
Other regulatory assets		248			132
Other		291			272

Total deferred charges and other assets		2,865			2,667

Total Assets	$	36,962		$	35,178

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

II-37

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



Liabilities and Stockholders’ Equity	2004		2003

	(in millions)

Current Liabilities:
Securities due within one year	$	983	$	741
Notes payable		426		568
Accounts payable		885		688
Customer deposits		200		189
Accrued taxes -
Income taxes		47		46
Other		243		249
Accrued interest		179		185
Accrued vacation pay		137		129
Accrued compensation		431		437
Other		260		273

Total current liabilities		3,791		3,505

Long-term Debt (See accompanying statements)		10,488		10,164

Long-term Debt Payable to Affiliated Trusts (See accompanying statements)		1,961		—

Mandatorily Redeemable Preferred Securities (See accompanying statements)		—		1,900

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		5,237		4,837
Deferred credits related to income taxes		373		408
Accumulated deferred investment tax credits		552		579
Employee benefit obligations		864		765
Asset retirement obligations		903		845
Other cost of removal obligations		1,296		1,260
Miscellaneous regulatory liabilities		350		572
Other		308		272

Total deferred credits and other liabilities		9,883		9,538

Total Liabilities		26,123		25,107

Preferred Stock of Subsidiaries (See accompanying statements)		561		423

Common Stockholders’ Equity (See accompanying statements)		10,278		9,648

Total Liabilities and Stockholders’ Equity	$	36,962	$	35,178

Commitments and Contingent Matters (See notes)

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

II-38

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



		2004			2003			2004			2003

		(in millions)						(percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds -
Maturity	Interest Rates
2006	6.50% to 6.90%	$	45		$	45
2025 through 2026	6.88% to 7.45%		60			60

Total first mortgage bonds			105			105

Long-term senior notes and debt -
Maturity	Interest Rates
2004	4.88% to 7.25%		—			580
2005	5.49% to 5.50%		379			379
2006	1.60% to 6.20%		674			679
2007	2.79% to 7.13%		1,220			929
2008	3.13% to 6.55%		462			458
2009	4.10% to 7.27%		169			43
2010 through 2044	4.00% to 8.12%		4,535			4,242
Adjustable rates (at 1/1/05):
2004	1.27% to 2.44%		—			89
2005	1.66% to 3.63%		563			492
2006	2.09%		195			195
2007	3.76%		90			47
2009	2.48% to 2.76%		440			—

Total long-term senior notes and debt			8,727			8,133

Other long-term debt -
Pollution control revenue bonds -
Maturity	Interest Rates
Collateralized:
2006	5.25%		12			12
2024	5.50%		24			24
Variable rates (at 1/1/05):
2015 through 2017	2.01% to 2.16%		90			90
Non-collateralized:
2012 through 2034	1.08% to 5.45%		850			850
Variable rates (at 1/1/05):
2011 through 2038	1.24% to 2.65%		1,565			1,565

Total other long-term debt			2,541			2,541

Capitalized lease obligations			115			107

Unamortized debt (discount), net			(17	)		(21	)

Total long-term debt (annual interest requirement — $496 million)			11,471			10,865

Less amount due within one year			983			701

Long-term debt excluding amount due within one year			10,488			10,164			45.1	%		45.9	%

II-39

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



		2004			2003			2004			2003

		(in millions)						(percent of total)
Long-term Debt Payable to Affiliated Trusts:
Maturity	Interest Rates
2027 through 2041	7.20% to 8.19%		436			—
2042	4.75% to 7.13%		1,319			—
2044	5.88%		206			—

Total long-term debt payable to affiliated trusts (annual interest requirement — $128 million)			1,961			—			8.4			0.0

Mandatorily Redeemable Preferred Securities:
$25 liquidation value -
Maturity	Interest Rates
2028 through 2042	6.85% to 7.63%		—			944
$1,000 liquidation value -
Maturity	Interest Rates
2027 through 2042	4.75% to 8.19%		—			996

Total mandatorily redeemable preferred securities			—			1,940
Less amount due within one year			—			40

Total mandatorily redeemable preferred securities excluding amount due within one year			—			1,900			0.0			8.6

Preferred Stock of Subsidiaries:
$100 cumulative par or stated value — 4.20% to 7.00%			100			98
$25 par or stated value —
Cumulative — 5.20% to 5.83%			294			200
Non-cumulative — 6.00%			44			—
$100,000 cumulative par or stated value — 4.95%			123			125

Total preferred stock of subsidiaries (annual dividend requirement — $30 million)			561			423			2.4			1.9

Common Stockholders’ Equity:
Common stock, par value $5 per share —			3,709			3,675
Authorized — 1 billion shares
Issued — 2004: 742 million shares
— 2003: 735 million shares
Treasury — 2004: 0.2 million shares
— 2003: 0.2 million shares
Paid-in capital			869			747
Treasury, at cost			(6	)		(4	)
Retained earnings			5,839			5,343
Accumulated other comprehensive income (loss)			(133	)		(113	)

Total common stockholders’ equity			10,278			9,648			44.1			43.6

Total Capitalization		$	23,288		$	22,135			100.0	%		100.0	%

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

II-40

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


	Common Stock
											Accumulated
	Par		Paid-In					Retained			Other Comprehensive
	Value		Capital		Treasury			Earnings			Income (Loss)			Total

	(in millions)
Balance at December 31, 2001	$	3,503	$	14	$	(57	)	$	4,517		$	7		$	7,984
Net income		—		—		—			1,318			—			1,318
Other comprehensive income (loss)		—		—		—			—			(89	)		(89	)
Stock issued		80		322		55			(6	)		—			451
Cash dividends		—		—		—			(958	)		—			(958	)
Other		—		2		(1	)		3			—			4

Balance at December 31, 2002		3,583		338		(3	)		4,874			(82	)		8,710
Net income		—		—		—			1,474			—			1,474
Other comprehensive income (loss)		—		—		—			—			(31	)		(31	)
Stock issued		92		408		—			—			—			500
Cash dividends		—		—		—			(1,004	)		—			(1,004	)
Other		—		1		(1	)		(1	)		—			(1	)

Balance at December 31, 2003		3,675		747		(4	)		5,343			(113	)		9,648
Net income		—		—		—			1,532			—			1,532
Other comprehensive income (loss)		—		—		—			—			(20	)		(20	)
Stock issued		34		122		—			—			—			156
Cash dividends		—		—		—			(1,044	)		—			(1,044	)
Other		—		—		(2	)		8			—			6

Balance at December 31, 2004	$	3,709	$	869	$	(6	)	$	5,839		$	(133	)	$	10,278

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

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



	2004			2003			2002

	(in millions)
Consolidated Net Income	$	1,532		$	1,474		$	1,318

Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(11), $(11), and $(18), respectively		(20	)		(17	)		(31	)
Change in fair value of marketable securities, net of tax of $(4)		6			—			—
Changes in fair value of qualifying hedges, net of tax of $(12), $(2), $(45), and respectively		(18	)		(17	)		(60	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $7, $1, and $1, respectively		12			3			2

Total other comprehensive income (loss)		(20	)		(31	)		(89	)

Consolidated Comprehensive Income	$	1,512		$	1,443		$	1,229

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

II-41

NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2004 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Southern Company is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies — Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric — provide electric service in four Southeastern states. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power — related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS — the system service company — provides, at cost, specialized services to Southern Company and the subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in the State of Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary. All material intercompany items have been eliminated in consolidation. Certain prior years’ data presented in the financial statements have been reclassified to conform with the current year presentation.

Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both the Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the retail operating companies and Southern Power are subject to regulation by the FERC, and the retail operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow accounting principles generally accepted in the United States and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Related Party Transactions

Alabama Power and Georgia Power purchase synthetic fuel from Alabama Fuel Products, LLC (AFP), an entity in which Southern Holdings holds a 30 percent ownership interest. Total fuel purchases for 2004, 2003, and 2002 were $409 million, $312 million, and $217 million, respectively. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings, provides fuel transportation services to AFP that are ultimately reflected in the cost of the synthetic fuel billed to Alabama Power and Georgia Power. In connection with these services, the related revenues of approximately $82 million, $65 million, and $35 million in 2004, 2003, and 2002, respectively, have been eliminated against fuel expense in the financial statements. SSI also provides additional services to AFP, as well as to a related party of AFP. Revenues from these transactions totaled approximately $24 million, $20 million, and $15 million, in 2004, 2003, and 2002, respectively.

Revenues

Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the retail operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.

II-42

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

Southern Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues despite an increase in customer bankruptcies.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $134 million in 2004, $138 million in 2003, and $134 million in 2002. Alabama Power and Georgia Power have contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively. Construction of an on-site dry storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units. Also, the facility will be able to be expanded to provide storage through 2025. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is scheduled to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry storage facility became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant.

Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Alabama Power and Georgia Power — based on its ownership interest — estimate their respective remaining liability at December 31, 2004 under this law to be approximately $9 million and $7 million.

Regulatory Assets and Liabilities

The retail operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:


	2004			2003			Note

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

Total	$	(343	)	$	(698	)

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(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.

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

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

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

II-43

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

In the event that a portion of a retail operating company’s operations is no longer subject to the provisions of FASB Statement No. 71, such company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the retail operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are currently reflected in rates.

Income Taxes

Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property.

Depreciation and Amortization

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

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

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

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, Southern Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. Although Statement No. 143 does not permit the continued accrual of future retirement costs for long-lived assets that the Company does not have a legal obligation to retire, the retail operating companies have received accounting guidance from their respective state PSCs allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets as a regulatory liability. Therefore, the retail operating companies had no cumulative effect to net income resulting from the adoption of Statement No. 143.

The liability recognized to retire long-lived assets primarily relates to Southern Company’s nuclear facilities, which include Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2004 was $905 million. In addition, the retail operating companies have retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The retail operating companies have also identified retirement obligations related to certain transmission and distribution facilities. However, liabilities for the removal of these transmission and distribution assets

II-44

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

have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The retail operating companies will continue to recognize in the statements of income allowed removal costs in accordance with each company’s respective regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

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


	2004			2003

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

Balance end of year	$	903		$	845

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC’s regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state PSCs. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC to ensure that — over time — the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.

Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current studies as of December 31, 2004 for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in plants Hatch and Vogtle were as follows:


	Plant		Plant		Plant
	Farley		Hatch		Vogtle

Decommissioning periods:
Beginning year		2017		2034		2027
Completion year		2046		2065		2048

	(in millions)

Site study costs:
Radiated structures	$	892	$	497	$	452
Non-radiated structures		63		49		58

Total	$	955	$	546	$	510

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

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


	Plant		Plant		Plant
	Farley		Hatch		Vogtle

	(in millions)
Amount expensed in 2004	$	18	$	7	$	2
Accumulated provisions:
External trust funds, at fair value	$	446	$	294	$	165
Internal reserves		29		—		2

Total	$	475	$	294	$	167

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

II-45

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

Plant Hatch. In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of units 1 and 2 until 2034 and 2038, respectively. Alabama Power filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years. The NRC is expected to rule on the application by July 2005. Alabama Power and Georgia Power expect their respective state PSCs to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized

In accordance with regulatory treatment, the retail operating companies record AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. Interest related to the construction of new facilities not included in the retail operating companies’ regulated rates is capitalized in accordance with standard interest capitalization requirements.

Cash payments for interest totaled $551 million, $603 million, and $560 million in 2004, 2003, and 2002, respectively, net of amounts capitalized of $36 million, $49 million, and $59 million, respectively.

Property, Plant, and Equipment

The cost of replacements of property — exclusive of minor items of property — is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power accrues estimated refueling costs in advance of the unit’s next refueling outage. Georgia Power defers and amortizes refueling costs over the unit’s operating cycle before the next refueling. The refueling cycles for Alabama Power and Georgia Power range from 18 to 24 months for each unit. In accordance with retail accounting orders, both Georgia Power and Savannah Electric will defer the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortize such costs over 10 years, which approximates the expected maintenance cycle.

Impairment of Long-Lived Assets and Intangibles

Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under “Plant McIntosh Construction Project” for information on a regulatory disallowance by the Georgia PSC in December 2004.

Storm Damage Reserves

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

II-46

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

Environmental Cost Recovery

Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. Alabama Power, Gulf Power, and Mississippi Power have each received authority from their respective state PSCs to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the state PSCs, these rates are adjusted annually. Georgia Power and Savannah Electric continue to recover environmental costs through their base rates.

Leveraged Leases

Southern Company has several leveraged lease agreements — ranging up to 45 years — that relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for rent or depreciation and amortization, as well as interest on long-term debt related to these investments.

Southern Company’s net investment in leveraged leases consists of the following at December 31:


	2004			2003

	(in millions)
Net rentals receivable	$	1,755		$	1,512
Unearned income		(779	)		(674	)

Investment in leveraged leases		976			838
Deferred taxes arising from leveraged leases		(392	)		(351	)

Net investment in leveraged leases	$	584		$	487

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


	2004		2003		2002

	(in millions)
Pretax leveraged lease income	$	70	$	66	$	58
Income tax expense		27		23		20

Net leveraged lease income	$	43	$	43	$	38

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

Generally, materials and supplies include the average costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Stock Options

Southern Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value on the date of grant.

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


	As		Pro
	Reported		Forma

2004
Net income (in millions)	$	1,532	$	1,516
Earnings per share (dollars):
Basic	$	2.07	$	2.05
Diluted	$	2.06	$	2.04
2003
Net income (in millions)	$	1,474	$	1,456
Earnings per share (dollars):
Basic	$	2.03	$	2.00
Diluted	$	2.02	$	1.99
2002
Net income (in millions)	$	1,318	$	1,299
Earnings per share (dollars):
Basic	$	1.86	$	1.83
Diluted	$	1.85	$	1.82

The estimated fair values of stock options granted in 2004, 2003, and 2002 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:


	2004			2003			2002

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

II-47

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

Financial Instruments

Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets or liabilities as appropriate until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.

Southern Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.

The other Southern Company financial instruments for which the carrying amount does not equal fair value at December 31 were as follows:


	Carrying		Fair
	Amount		Value

	(in millions)
Long-term debt:
At December 31, 2004	$	13,317	$	13,560
At December 31, 2003		10,759		10,971
Preferred securities:
At December 31, 2004		—		—
At December 31, 2003		1,940		2,059

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.

Variable Interest Entities

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

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

2. RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly

II-48

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

compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees. The retail operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ended December 31, 2005, postretirement trust contributions are expected to total approximately $34.5 million.

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

Pension Plans

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


	Projected
	Benefit Obligations
	2004			2003

	(in millions)
Balance at beginning of year	$	4,573		$	4,094
Service cost		128			115
Interest cost		270			261
Benefits paid		(207	)		(197	)
Plan amendments		6			11
Actuarial (gain) loss		305			289

Balance at end of year	$	5,075		$	4,573


	Plan Assets
	2004			2003

	(in millions)
Balance at beginning of year	$	5,159		$	4,600
Actual return on plan assets		501			735
Employer contributions		23			-
Benefits paid		(207	)		(176	)

Balance at end of year	$	5,476		$	5,159

Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.


				Plan Assets
	Target			2004			2003

Domestic equity		37	%		36	%		37	%
International equity		20			20			20
Fixed income		26			26			24
Real estate		10			10			11
Private equity		7			8			8

Total		100	%		100	%		100	%

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


	2004			2003

	(in millions)
Funded status	$	401		$	586
Unrecognized transition amount		(14	)		(26	)
Unrecognized prior service cost		292			314
Unrecognized net (gain) loss		185			(70	)

Prepaid pension asset, net	$	864		$	804

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


	2004			2003

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

Prepaid pension asset, net	$	864		$	804

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


	2004			2003			2002

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

Net pension cost (income)	$	(44	)	$	(99	)	$	(117	)

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


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

II-49

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

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:


	Accumulated
	Benefit Obligations
	2004			2003

	(in millions)
Balance at beginning of year	$	1,655		$	1,461
Service cost		27			25
Interest cost		93			93
Benefits paid		(68	)		(66	)
Actuarial (gain) loss		72			142
Plan amendments		(67	)		-

Balance at end of year	$	1,712		$	1,655


	Plan Assets
	2004			2003

	(in millions)
Balance at beginning of year	$	522		$	417
Actual return on plan assets		64			70
Employer contributions		74			101
Benefits paid		(68	)		(66	)

Balance at end of year	$	592		$	522

Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.


				Plan Assets
	Target			2004			2003

Domestic equity		43	%		43	%		44	%
International equity		17			18			18
Fixed income		33			32			31
Real estate		4			4			4
Private equity		3			3			3

Total		100	%		100	%		100	%

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


	2004			2003

	(in millions)
Funded status	$	(1,120	)	$	(1,133	)
Unrecognized transition obligation		129			144
Unrecognized prior service cost		130			211
Unrecognized net loss (gain)		408			357
Fourth quarter contributions		30			19

Accrued liability recognized in the balance sheets	$	(423	)	$	(402	)

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


	2004			2003			2002

				(in millions)
Service cost	$	28		$	25		$	21
Interest cost		93			93			91
Expected return on plan assets		(50	)		(47	)		(42	)
Net amortization		35			30			29

Net postretirement cost	$	106		$	101		$	99

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

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

II-50

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


	Benefit		Subsidy
	Payments		Receipts			Total

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

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:


	2004			2003			2002

Discount		5.75	%		6.00	%		6.50	%
Annual salary increase		3.50			3.75			4.00
Long-term return on plan assets		8.50			8.50			8.50

The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

An additional assumption used in measuring the accumulated postretirement benefit obligation was a weighted average medical care cost trend rate of 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2004 as follows:


	1 Percent		1 Percent
	Increase		Decrease

	(in millions)
Benefit obligation	$	156	$	123
Service and interest costs		9		8

Employee Savings Plan

Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2004, 2003, and 2002 were $56 million, $55 million, and $53 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

Mirant Related Matters

Mirant Bankruptcy

In July 2003, Mirant Corporation (Mirant) filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code with the U.S. Bankruptcy Court (Bankruptcy Court). In January 2005, Mirant filed its plan of reorganization (POR), which must be approved by the Bankruptcy Court. Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 under “Guarantees” and with various lawsuits related to Mirant discussed below. Southern Company has paid approximately $1.4 million in connection with the guarantees. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Based on management’s assessment of the collectibility of this receivable, Southern Company reserved approximately $12.5 million.

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

II-51

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

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

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

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

Mirant Securities Litigation

In November 2002, Southern Company, certain former and current senior officers of Southern Company, and 12 underwriters of Mirant’s initial public offering were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. Several other similar lawsuits filed subsequently were consolidated into this litigation in the U.S. District Court for the Northern District of Georgia. The amended complaint is based on allegations related to alleged improper energy trading and marketing activities involving the California energy market, alleged false statements and omissions in Mirant’s prospectus for its initial public offering and in subsequent public statements by Mirant, and accounting-related issues previously disclosed by Mirant. The lawsuit purports to include persons who acquired Mirant securities between September 26, 2000 and September 5, 2002.

In July 2003, the court dismissed all claims based on Mirant’s alleged improper energy trading and marketing activities involving the California energy market. The remaining claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seek to impose liability on Southern Company based on allegations that Southern Company was a “control person” as to Mirant prior to the spin off date. Southern Company filed an answer to the consolidated amended class action complaint in September 2003. Plaintiffs have also filed a motion for class certification.

As a result of Mirant’s Chapter 11 proceeding, the Bankruptcy Code automatically stayed all litigation as to Mirant. In November 2003, the Bankruptcy Court granted a request to extend this automatic stay to all other non-debtor defendants, including Southern Company and its current and/or former officers named as defendants in the Mirant securities litigation. However, the Bankruptcy Court authorized Mirant to agree with parties in pending actions to allow discovery or other matters to proceed without violating the stay. Mirant and plaintiffs’ counsel in the Mirant securities litigation agreed that document discovery could proceed. In October 2003, the Bankruptcy Court entered an order authorizing Southern Company’s insurance companies to pay related defense costs.

Under certain circumstances, Southern Company will be obligated under its Bylaws to indemnify the four current and/or former Southern Company officers who served as directors of Mirant at the time of its initial public offering through the date of the spin off and who are also named as defendants in this lawsuit. The final outcome of these matters cannot now be determined.

II-52

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

Southern Company Employee Savings Plan Litigation

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

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

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

Environmental Matters

New Source Review Actions

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

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

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

II-53

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

Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states to apply to facilities in the Southern Company system. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Plant Wansley Environmental Litigation

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

Environmental Remediation

Georgia Power has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act. In 1995, the EPA designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia, that is listed on the federal National Priorities List. As of December 31, 2004, Georgia Power had recorded approximately $6 million in cumulative expenses associated with its agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. Additional claims for recovery of

II-54

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

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

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

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

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

Generation Interconnection Agreements

Market-Based Rate Authority

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

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

II-55

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

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

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

Race Discrimination Litigation

In July 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against Georgia Power, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the U.S. District Court for the Northern District of Georgia. The lawsuit also raised claims on behalf of a purported class. The plaintiffs seek compensatory and punitive damages in an unspecified amount, as well as injunctive relief. In August 2000, the lawsuit was amended to add four more plaintiffs. Also, an additional indirect subsidiary of Southern Company, Southern Company Energy Solutions, was named a defendant.

In October 2001, the district court denied the plaintiffs’ motion for class certification. The U.S. Court of Appeals for the Eleventh Circuit subsequently denied plaintiffs’ petition seeking permission to file an appeal of the October 2001 decision. In March 2003, the U.S. District Court for the Northern District of Georgia granted summary judgment in favor of the defendants on all claims raised by all seven plaintiffs. In April 2003, plaintiffs filed an appeal to the U.S. Court of Appeals for the Eleventh Circuit challenging these adverse summary judgment rulings, as well as the District Court’s October 2001 ruling denying class certification. On November 10, 2004, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit issued an order affirming in all respects the district court’s rulings. On December 1, 2004, the plaintiffs filed a petition for rehearing seeking a review of the November 2004 order by the entire Eleventh Circuit panel of judges. If this petition is denied, the plaintiffs will have 90 days from the date of the court’s order denying the petition to file a petition for writ of certiorari to the U.S. Supreme Court. The final outcome of this matter cannot now be determined.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and its subsidiaries believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit. An adverse outcome in these matters could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

II-56

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

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

In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom, were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Income Tax Matters

Synthetic Fuel Tax Credits

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

In June 2003, the IRS completed a review of the scientific validity of test procedures and results that have been presented as evidence that a significant chemical change occurred in such synthetic fuel and announced that it has determined that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner. The IRS stated that the processes they approved do not produce the level of chemical change required by Section 29, but they will, nevertheless, resume issuing private letter rulings. The IRS required taxpayers applying for future rulings, as well as those already holding rulings, to implement and maintain certain sampling and quality control procedures, as well as additional documentation and record retention procedures. Both AFP and Carbontronics have private letter rulings from the IRS that concluded significant chemical change occurred based on the procedures and results submitted. In addition, both entities regularly use independent laboratories and experts to test for chemical change. These tests replicated significant chemical changes consistent with the procedures submitted with the private letter rulings.

In October 2003, the Senate Governmental Affairs Permanent Subcommittee on Investigations announced that it has begun a separate investigation of the synthetic fuel industry and its producers for potential abuses of these tax credits. There has been no significant activity related to this investigation to date.

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

II-57

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

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

Leveraged Lease Transactions

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

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

Alabama Power Retail Regulatory Matters

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

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

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

II-58

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

Georgia Power Retail Rate Activity

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

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

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

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

Gulf Power and Alabama Power Storm Damage Recovery

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

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

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

Plant McIntosh Construction Project

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

II-59

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

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

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

Plant Franklin Construction Project

Southern Power completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. As of December 31, 2004, Southern Power’s investment in Unit 3 of Plant Franklin was $172 million. The final outcome of this matter cannot now be determined.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Alabama Electric Cooperative, Inc.

Georgia Power owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation for a combustion turbine unit at Intercession City, Florida.

Southern Power owns an undivided interest in Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.

At December 31, 2004, Alabama Power’s, Georgia Power’s, and Southern Power’s ownership and investment (exclusive of nuclear fuel) in jointly owned facilities with the above entities were as follows:

Jointly Owned Facilities

Percent

Amount of

Accumulated

Ownership

Investment

Depreciation

(in millions)

Plant Vogtle (nuclear)

45.7

3,304

1,756

Plant Hatch (nuclear)

50.1

932

485

Plant Miller (coal) Units 1 and 2

91.8

776

356

Plant Scherer (coal) Units 1 and 2

8.4

114

Plant Wansley (coal)

53.5

394

164

Rocky Mountain (pumped storage)

25.4

169

Intercession City (combustion turbine)

33.3

Plant Stanton (combined cycle) Unit A

65.0

156

II-60

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

Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities — except for Rocky Mountain and Intercession City — as agents for their respective co-owners. The companies’ proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income.

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

Mirant was included in the consolidated federal tax return through April 2, 2001. In December 2004, the IRS concluded its audit for the tax years 2000 and 2001, and Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements, Mirant agreed to indemnify Southern Company for subsequent assessment of any additional taxes related to its transactions prior to the spin off. However, as a result of Mirant’s bankruptcy, Southern Company must seek reimbursement as an unsecured creditor. For additional information, see Note 3 under “Mirant Related Matters — Mirant Bankruptcy.”

At December 31, 2004, the tax-related regulatory assets and liabilities were $865 million and $374 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

Details of income tax provisions are as follows:


	2004		2003		2002

	(in millions)
Total provision for income taxes:
Federal —
Current	$	14	$	141	$	284
Deferred		482		393		167

		496		534		451

State —
Current		15		44		64
Deferred		76		34		13

		91		78		77

Total	$	587	$	612	$	528

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

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:


	2004			2003

	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	4,252		$	3,854
Property basis differences		1,047			1,035
Leveraged lease basis differences		447			351
Employee benefit obligations		305			283
Under recovered fuel clause		209			70
Premium on reacquired debt		132			133
Other		195			165

Total		6,587			5,891

Deferred tax assets:
Federal effect of state deferred taxes		246			220
State effect of federal deferred taxes		111			99
Employee benefit obligations		190			161
Other property basis differences		162			171
Deferred costs		105			128
Alternative minimum tax carryforward		106			—
Other		386			436

Total		1,306			1,215

Total deferred tax liabilities, net		5,281			4,676
Portion included in prepaid expenses (accrued income taxes), net		(57	)		150
Deferred state tax assets		13			11

Accumulated deferred income taxes in the balance sheets	$	5,237		$	4,837

At December 31, 2004, Southern Company also had available State of Georgia net operating loss carryforward deductions totaling $1.0 billion, which could result in net state income tax benefits of $59 million, if utilized. These deductions will expire between 2010 and 2021. During 2004, Southern Company realized $10 million in such state income tax benefits. Beginning in 2002, the State of Georgia allowed the filing of a combined return, which should substantially reduce any additional net operating loss carryforwards.

In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $27 million in 2004, $29 million in 2003, and $27 million in 2002. At December 31, 2004, all investment tax credits

II-61

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

available to reduce federal income taxes payable had been utilized.

The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred dividends of subsidiaries, as a result of the following:


	2004			2003			2002

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

Effective income tax rate		27.3	%		29.1	%		28.4	%

6. FINANCING

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

Southern Company and the retail operating companies have each formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Southern Company and the retail operating companies through the issuance of junior subordinated notes totaling $2.0 billion, which constitute substantially all assets of these trusts and are reflected on the balance sheets as Long-term Debt Payable to Affiliated Trusts. Southern Company and the retail operating companies each consider that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2004, preferred securities of $1.9 billion were outstanding. Southern Company guarantees the notes related to $574 million of these securities issued on its behalf. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Long-Term Debt Due Within One Year

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


	2004		2003

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

Total	$	983	$	701

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

Assets Subject to Lien

Each of Southern Company’s subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. The retail operating companies’ mortgages, which secure the first mortgage bonds issued by the retail operating companies, constitute a direct first lien on substantially all of the retail operating companies’ respective fixed property and franchises. Georgia Power discharged its mortgage in 2002, and the lien was removed. There are no agreements or other arrangements among the subsidiary companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.

Bank Credit Arrangements

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


	Amount of Credit				Expires
							2006 &
Company	Total		Unused		2005		beyond

			(in millions)
Alabama Power	$	868	$	868	$	643	$	225
Georgia Power		773		773		423		350
Gulf Power		57		57		57		–
Mississippi Power		101		101		101		–
Savannah Electric		80		80		70		10
Southern Company		1,000		1,000		500		500
Southern Power		325		325		–		325
Other		30		30		30		–

Total	$	3,234	$	3,234	$	1,824	$	1,410

II-62

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

Approximately $1.2 billion of the credit facilities expiring in 2005 allow the execution of term loans for an additional two-year period, and $275 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates but also allow for competitive bid loans.

All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are less than one-eighth of 1 percent for Southern Company and the retail operating companies and less than three-eighths of 1 percent for Southern Power. Compensating balances are not legally restricted from withdrawal. Included in the total $3.2 billion of unused credit arrangements is $2.5 billion of syndicated credit arrangements that require the payment of agent fees.

Most of the credit arrangements with banks have covenants that limit debt levels to 65 percent of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts. At December 31, 2004, Southern Company, Southern Power, and the retail operating companies were each in compliance with their respective debt limit covenants.

In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. Except for Southern Power, the cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has the credit arrangement with the bank. Southern Power’s bank credit arrangements have a cross default to Southern Company’s indebtedness, which, if triggered, would require prepayment of debt related to projects financed under the credit arrangement that are not complete. Southern Company has committed to fund at least 35 percent on Southern Power’s construction project financing and to pay for construction overruns to the extent that Southern Power’s cash flow is insufficient. Southern Company and its subsidiaries are currently in compliance with all such covenants.

Borrowings under certain retail operating companies’ unused credit arrangements totaling $40 million would be prohibited if the borrower experiences a material adverse change, as defined in such arrangements. Initial borrowings for new projects under Southern Power’s credit facility would be prohibited if Southern Power or Southern Company experiences a material adverse change, as defined in that credit facility.

A portion of the $3.2 billion unused credit with banks is allocated to provide liquidity support to the retail operating companies’ variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2004 was $662 million.

Southern Company, the retail operating companies, and Southern Power borrow through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the retail operating companies may also borrow through extendible commercial note programs. The amount of commercial paper and extendible commercial notes outstanding and included in notes payable on the balance sheets at December 31, 2004 and December 31, 2003 was $377 million and $568 million, respectively. During 2004, the peak amount outstanding for commercial paper was $848 million, and the average amount outstanding was $511 million. The average annual interest rate on commercial paper was 1.3 percent in both 2004 and 2003.

Financial Instruments

The retail operating companies, Southern Power, and Southern Company GAS enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the retail operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. Each of the retail operating companies has implemented fuel-hedging programs at the instruction of their respective state PSCs. Together with Southern Power, the retail operating companies may enter into hedges of forward electricity sales. Southern Company GAS has gas-hedging programs to substantially mitigate its exposure to price volatility for its gas purchases.

At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

II-63

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


	Amounts

	(in millions)
Regulatory liabilities, net	$	12.8
Other comprehensive income		(1.7	)
Net income		(0.6	)


Total fair value	$	10.5

The fair value gains or losses for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. For Southern Power and Southern Company GAS, the fair value gains or losses for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. For 2004, 2003, and 2002, approximately $(3) million, $22 million, and $3 million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to fuel expense. For the year 2005, approximately $3 million of pre-tax gains are expected to be reclassified from other comprehensive income to fuel expense. There was no significant ineffectiveness recorded in earnings for any period presented. Southern Company has energy-related hedges in place up to and including 2007.

Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to changes in interest rates. Derivatives related to fixed-rate securities are accounted for as fair value hedges. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

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

Fair Value Hedges

Variable

Fair

Rate

Notional

Value

Company

Maturity

Paid

Amount

Gain

(in millions)

Southern Company

2007

6-month

400

17.1

LIBOR - 0.10%

2009

6-month

0.8

LIBOR + 2.92%

Cash Flow Hedges


		Weighted Average			Fair
		Fixed			Value
		Rate	Notional		Gain/
Company	Maturity	Paid	Amount		(Loss)

			(in millions)
Alabama Power	2007	2.01*	$	536	$	5.6
	2006	1.89		195		3.2
	2035	5.68		250		(16.0	)

Georgia Power	2005	1.96		250		0.3
	2005	1.56		50		0.1
	2015	4.66		250		0.7
	2015	5.03		100		(0.9	)
	2006	6.00**		150		(0.1	)
	2005-07	2.35-3.85***		400		0.6

Savannah Electric	2007	2.50*		14		0.1

*		Hedged using the Bond Market Association Municipal Swap Index.

**		Costless collar with cap rate of 6.00 percent.

***		Capped rate based on formula approximating the yield on tax-exempt auction rate securities.

For fair value hedges where the hedged item is an asset, liability, or firm commitment, the changes in the fair value of the hedging derivatives are recorded in earnings and are offset by the changes in the fair value of the hedged item.

The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2004, 2003, and 2002, the Company settled losses of $7 million, $116 million, and $14 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. For 2004, 2003, and 2002, approximately $23 million, $26 million, and $6 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, pre-tax losses of approximately $11 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2035.

II-64

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

7. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently estimated to total $2.2 billion in 2005, $2.5 billion in 2006, and $3.2 billion in 2007. These amounts include $64 million, $45 million, and $39 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included herein under “Fuel and Purchased Power Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program. Southern Company has approximately 1,200 megawatts of additional generating capacity scheduled to be placed in service during 2005. In addition, capital improvements to generation, transmission, and distribution facilities — including those to meet environmental standards — will continue.

Long-Term Service Agreements

The retail operating companies and Southern Power have entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned by the subsidiaries. The LTSAs stipulate that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

In general, except for Southern Power’s Plant Dahlberg, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg agreement is in effect through the first major inspection of each unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.4 billion over the remaining life of the agreements, which may range up to 30 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers.

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

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

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2004. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2004 were as follows:


			Coal and
	Natural		Nuclear		Purchased
Year	Gas		Fuel		Power

(in millions)
2005	$	747	$	3,135	$	171
2006		635		2,652		178
2007		398		1,922		179
2008		303		777		181
2009		290		349		161
2010 and thereafter		2,678		193		680

Total commitments	$	5,051	$	9,028	$	1,550

II-65

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

Additional commitments for fuel will be required to supply Southern Company’s future needs.

Operating Leases

In May 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel. The facility cost approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. In 2003, approximately $11 million in lease termination costs were also included in operation expenses. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50 percent of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The initial lease term ends in 2011, and the lease includes a purchase and renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4 percent of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, Mississippi Power may elect to renew for 10 years. If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17 percent of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power’s option, it may either exercise its purchase option or the facility can be sold to a third party.

The lease provides for a residual value guarantee — approximately 73 percent of the acquisition cost — by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the asset. A liability of approximately $13 million for the fair market value of this residual value guarantee is included in the balance sheet as of December 31, 2004.

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


	Plant		Rail
Year	Daniel		Cars		Other		Total

	(in millions)
2005	$	29	$	38	$	56	$	123
2006		29		35		42		106
2007		29		26		34		89
2008		29		25		27		81
2009		29		23		23		75
2010 and thereafter		56		98		105		259

Total minimum payments	$	201	$	245	$	287	$	733

For the retail operating companies, the rail car lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2006, 2009, and 2011, and the maximum obligations are $66 million, $19.5 million, and $72 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.

Guarantees

Southern Company has made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant’s trading and marketing subsidiaries. The total notional amount of guarantees outstanding at December 31, 2004 is less than $20 million, all of which will expire by 2009.

Southern Company has executed a keep-well agreement with a subsidiary of Southern Holdings to make capital contributions in the event of any shortfall in payments due under a participation agreement with an entity in which the subsidiary holds a 30 percent investment. The maximum aggregate amount of Southern Company’s liability under this keep-well agreement is $50 million.

As discussed earlier in this Note under “Operating Leases,” Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees.

II-66

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

8. COMMON STOCK

Stock Issued

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

Shares Reserved

At December 31, 2004, a total of 39.2 million shares was reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option plan).

Stock Option Plan

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


	Shares			Average
	Subject			Option Price
	To Option			Per Share

Balance at December 31, 2001		29,630,885			17.46
Options granted		8,040,495			25.28
Options canceled		(104,212	)		19.64
Options exercised		(4,892,354	)		15.16

Balance at December 31, 2002		32,674,814			19.72
Options granted		7,165,398			27.98
Options canceled		(181,381	)		24.37
Options exercised		(5,725,336	)		16.56

Balance at December 31, 2003		33,933,495			21.97
Options granted		7,231,703			29.49
Options canceled		(72,225	)		26.85
Options exercised		(6,557,690	)		18.11

Balance at December 31, 2004		34,535,283		$	24.27

Shares reserved for future grants:
At December 31, 2002		46,788,994
At December 31, 2003		39,751,477
At December 31, 2004		32,583,523

Options exercisable:
At December 31, 2002		15,463,414
At December 31, 2003		18,874,426
At December 31, 2004		21,782,064

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

Dollar Price

Range of Options

13-20

20-26

26-32

Outstanding:

Shares (in thousands)

9,328

11,073

14,134

Average remaining life (in years)

4.5

6.2

8.1

Average exercise price

17.51

24.25

28.75

Exercisable:

Shares (in thousands)

9,328

8,918

3,536

Average exercise price

17.51

24.00

28.26

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to outstanding options under the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows:


	Average Common Stock Shares
	2004		2003		2002

	(in thousands)
As reported shares		738,879		726,702		708,161
Effect of options		4,197		5,202		5,409

Diluted shares		743,076		731,904		713,570

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2004, consolidated retained earnings included $4.1 billion of undistributed retained earnings of the subsidiaries. Of this amount, $313 million was restricted against the payment by the subsidiary companies of cash dividends on common stock under terms of bond indentures.

In accordance with the PUHCA, the subsidiaries are also restricted from paying common dividends from paid-in capital without SEC approval.

II-67

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

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988, Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies’ nuclear power plants. The act provides funds up to $10.76 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power — based on its ownership and buyback interests — is $201 million and $203 million, respectively, per incident, but not more than an aggregate of $20 million per company to be paid for each incident in any one year. The Price-Anderson Amendments Act expired in August 2002; however, the indemnity provisions of the act remain in place for commercial nuclear reactors.

Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.

Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.

Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $39 million and $43 million, respectively.

Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all “non-certified” terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL aggregate, which applies to non-certified claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

All retrospective assessments — whether generated for liability, property, or replacement power — may be subject to applicable state premium taxes.

10. SEGMENT AND RELATED INFORMATION

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

II-68

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

retail operating companies and Southern Power. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. Southern Power’s revenues from sales to the retail operating companies were $425 million, $313 million, and $183 million in 2004, 2003, and 2002, respectively. In addition, see Note 1 under “Related Party Transactions” for information regarding revenues from services for synthetic fuel production that are included in the cost of fuel purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

Business Segment


	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated

	(in millions)
2004
Operating revenues	$	11,300	$	701	$	(536	)	$	11,465	$	549		$	(112	)	$	11,902
Depreciation and amortization		857		51		—			908		47			—			955
Interest income		24		1		—			25		4			(2	)		27
Interest expense		518		66		—			584		84			(1	)		667
Income taxes		802		73		—			875		(288	)		—			587
Segment net income (loss)		1,309		112		—			1,421		112			(1	)		1,532
Total assets		33,524		2,067		(103	)		35,488		1,996			(522	)		36,962
Gross property additions		2,318		116		(415	)		2,019		91			—			2,110


	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated

	(in millions)
2003
Operating revenues	$	10,502	$	682	$	(437	)	$	10,747	$	526		$	(87	)	$	11,186
Depreciation and amortization		933		39		—			972		55			—			1,027
Interest income		33		—		—			33		6			(3	)		36
Interest expense		542		32		—			574		107			(3	)		678
Income taxes		760		85		—			845		(233	)		—			612
Segment net income (loss)		1,269		155		—			1,424		50			—			1,474
Total assets		31,506		2,409		(122	)		33,793		1,671			(286	)		35,178
Gross property additions		1,636		344		—			1,980		34			—			2,014


	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated

								(in millions)
2002
Operating revenues	$	10,109	$	299	$	(202	)	$	10,206	$	365		$	(57	)	$	10,514
Depreciation and amortization		970		18		—			988		59			—			1,047
Interest income		19		—		—			19		10			(7	)		22
Interest expense		559		9		—			568		105			(6	)		667
Income taxes		749		28		—			777		(249	)		—			528
Segment net income (loss)		1,242		54		—			1,296		23			(1	)		1,318
Total assets		30,367		2,086		(78	)		32,375		1,881			(535	)		33,721
Gross property additions		1,784		1,215		(390	)		2,609		119			—			2,728

II-69

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

Products and Services


	Electric Utilities Revenues
Year	Retail		Wholesale		Other		Total

		(in millions)

2004	$	9,732	$	1,341	$	392	$	11,465
2003		8,875		1,358		514		10,747
2002		8,728		1,168		310		10,206

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2004 and 2003 are as follows:


							Per Common Share (Note)
	Operating		Operating		Consolidated		Basic				Price Range
Quarter Ended	Revenues		Income		Net Income		Earnings		Dividends		High		Low

	(in millions)
March 2004	$	2,732	$	623	$	331	$	0.45	$	0.3500	$	30.87	$	29.10
June 2004		3,009		695		352		0.48		0.3500		30.59		27.86
September 2004		3,441		1,113		645		0.87		0.3575		30.65		28.86
December 2004		2,720		396		204		0.28		0.3575		33.92		29.95

March 2003	$	2,541	$	588	$	298	$	0.41	$	0.3425	$	30.81	$	27.71
June 2003		2,824		781		432		0.60		0.3425		31.81		27.94
September 2003		3,301		1,095		619		0.85		0.3500		30.53		27.76
December 2003		2,520		341		125		0.17		0.3500		30.40		28.65

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

II-70

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



	2004		2003		2002		2001		2000

Operating Revenues (in millions)	$	11,902	$	11,186	$	10,514	$	10,155	$	10,066
Total Assets (in millions)	$	36,962	$	35,178	$	33,721	$	31,856	$	33,282
Gross Property Additions (in millions)	$	2,110	$	2,014	$	2,728	$	2,617	$	2,225
Return on Average Common Equity (percent)		15.38		16.05		15.79		13.51		13.20
Cash Dividends Paid Per Share of Common Stock	$	1.415	$	1.385	$	1.355	$	1.34	$	1.34

Consolidated Net Income (in millions):
Continuing operations	$	1,532	$	1,474	$	1,318	$	1,120	$	994
Discontinued operations		—		—		—		142		319

Total	$	1,532	$	1,474	$	1,318	$	1,262	$	1,313

Earnings Per Share From Continuing Operations —
Basic	$	2.07	$	2.03	$	1.86	$	1.62	$	1.52
Diluted		2.06		2.02		1.85		1.61		1.52
Earnings Per Share Including Discontinued Operations —
Basic	$	2.07	$	2.03	$	1.86	$	1.83	$	2.01
Diluted		2.06		2.02		1.85		1.82		2.01

Capitalization (in millions):
Common stock equity	$	10,278	$	9,648	$	8,710	$	7,984	$	10,690
Preferred stock		561		423		298		368		368
Mandatorily redeemable preferred securities		—		1,900		2,380		2,276		2,246
Long-term debt payable to affiliated trusts		1,961		—		—		—		—
Long-term debt		10,488		10,164		8,714		8,297		7,843

Total excluding amounts due within one year	$	23,288	$	22,135	$	20,102	$	18,925	$	21,147

Capitalization Ratios (percent):
Common stock equity		44.1		43.6		43.3		42.2		50.6
Preferred stock		2.4		1.9		1.5		1.9		1.7
Mandatorily redeemable preferred securities		—		8.6		11.8		12.0		10.6
Long-term debt payable to affiliated trusts		8.4		—		—		—		—
Long-term debt		45.1		45.9		43.4		43.9		37.1

Total excluding amounts due within one year		100.0		100.0		100.0		100.0		100.0

Other Common Stock Data (Note):
Book value per share (year-end)	$	13.86	$	13.13	$	12.16	$	11.43	$	15.69
Market price per share (dollars):
High	$	33.920	$	31.810	$	30.850	$	26.000	$	35.000
Low		27.860		27.710		23.890		16.152		20.375
Close		33.520		30.250		28.390		25.350		33.250
Market-to-book ratio (year-end) (percent)		241.8		230.4		233.5		221.8		211.9
Price-earnings ratio (year-end) (times)		16.2		14.9		15.3		15.6		16.5
Dividends paid (in millions)	$	1,044	$	1,004	$	958	$	922	$	873
Dividend yield (year-end) (percent)		4.2		4.6		4.8		5.3		4.0
Dividend payout ratio (percent)		68.2		68.1		72.8		82.4		66.5
Shares outstanding (in thousands):
Average		738,879		726,702		708,161		689,352		653,087
Year-end		741,495		734,829		716,402		698,344		681,158
Stockholders of record (year-end)		125,975		134,068		141,784		150,242		160,116

Customers for Retail Operating Companies (year-end) (in thousands):
Residential		3,600		3,552		3,496		3,441		3,398
Commercial		578		564		553		539		527
Industrial		14		14		14		14		14
Other		5		6		5		4		5

Total		4,197		4,136		4,068		3,998		3,944

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

II-71

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



	2004		2003		2002		2001		2000

Employees (year-end)		25,642		25,762		26,178		26,122		26,021

Operating Revenues (in millions):
Residential	$	3,848	$	3,565	$	3,556	$	3,247	$	3,361
Commercial		3,346		3,075		3,007		2,966		2,918
Industrial		2,446		2,146		2,078		2,144		2,289
Other		92		89		87		83		32

Total retail		9,732		8,875		8,728		8,440		8,600
Sales for resale within service area		504		444		443		338		377
Sales for resale outside service area		837		914		725		836		600

Total revenues from sales of electricity		11,073		10,233		9,896		9,614		9,577
Other revenues		829		953		618		541		489

Total	$	11,902	$	11,186	$	10,514	$	10,155	$	10,066

Kilowatt-Hour Sales (in millions):
Residential		49,702		47,833		48,784		44,538		46,213
Commercial		50,037		48,372		48,250		46,939		46,249
Industrial		56,399		54,415		53,851		52,891		56,746
Other		1,005		998		1,000		977		970

Total retail		157,143		151,618		151,885		145,345		150,178
Sales for resale within service area		11,417		10,712		10,853		9,388		9,579
Sales for resale outside service area		23,822		29,808		21,698		21,380		17,190

Total		192,382		192,138		184,436		176,113		176,947

Average Revenue per Kilowatt-Hour (cents):
Residential		7.74		7.45		7.29		7.29		7.27
Commercial		6.69		6.36		6.23		6.32		6.31
Industrial		4.34		3.94		3.86		4.05		4.03
Total retail		6.19		5.85		5.75		5.81		5.73
Sales for resale		3.81		3.35		3.59		3.82		3.65
Total sales		5.76		5.33		5.37		5.46		5.41
Average Annual Kilowatt-Hour Use per Residential Customer		13,879		13,562		14,036		13,014		13,702
Average Annual Revenue per Residential Customer	$	1,074	$	1,011	$	1,023	$	949	$	996
Plant Nameplate Capacity Owned (year-end) (megawatts)		38,622		38,679		36,353		34,579		32,807
Maximum Peak-Hour Demand (megawatts):
Winter		28,467		31,318		25,939		26,272		26,370
Summer		34,414		32,949		32,355		29,700		31,359
System Reserve Margin (at peak) (percent)		20.2		21.4		13.3		19.3		8.1
Annual Load Factor (percent)		61.4		62.0		51.1		62.0		60.2
Plant Availability (percent):
Fossil-steam		88.5		87.7		84.8		88.1		86.8
Nuclear		92.8		94.4		90.3		90.8		90.5

Source of Energy Supply (percent):
Coal		64.6		66.4		65.7		67.5		72.3
Nuclear		14.4		14.8		14.7		15.2		15.1
Hydro		2.9		3.8		2.6		2.6		1.5
Oil and Gas		10.9		8.8		11.4		8.4		4.0
Purchased power		7.2		6.2		5.6		6.3		7.1

Total		100.0		100.0		100.0		100.0		100.0

II-72

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Alabama Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2004 and 2003, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of Alabama Power Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements (pages II-93 to II-118) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 28, 2005

II-74

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

OVERVIEW

Business Activities

Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards.

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

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

Key Performance Indicators

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

Key

2004

2004

Performance

Target

Actual

Indicator

Performance

Performance

Customer
Satisfaction

Top quartile in national and regional surveys

Top quartile

Peak Season
EFOR

2.81% or less

1.86

ROE

13.50

13.53

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

Earnings

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

The Company’s 2003 net income after dividends on preferred stock was $473 million, representing a $12 million (2.5 percent) increase from the prior year. This improvement was due primarily to higher retail sales, higher sales for resale, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses. In 2002, earnings were $461 million, representing a 19.3 percent increase from the prior year. This improvement was primarily attributable to increased territorial energy sales and higher retail rates when compared to the prior year. More favorable weather conditions in 2002 as compared to the unusually mild weather experienced in 2001 contributed to the increases in territorial sales. The increases in revenues were partially offset by increased non-fuel operating expenses.

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

II-75

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

RESULTS OF OPERATIONS

A condensed income statement is as follows:


					Increase (Decrease)
	Amount			From Prior Year
	2004				2004		2003			2002
					(in millions)
Operating revenues	$	4,236			$	276	$	250		$	124

Fuel		1,187				119		98			(31	)
Purchased power		413				98		66			(44	)
Other operation and maintenance		947				26		67			71
Depreciation and amortization		426				13		15			15
Taxes other than income taxes		243				14		11			2

Total operating expenses		3,216				270		257			13

Operating income		1,020				6		(7	)		111
Total other income and (expense)		(202	)			30		20			6
Income taxes		313				23		(2	)		44

Net income		505				13		15			73
Dividends on preferred stock		24				5		3			(1	)

Net income after dividends on preferred stock	$	481			$	8	$	12		$	74

Revenues

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


	Amount
	2004			2003			2002
	(in millions)
Retail — prior year	$	3,051		$	2,951		$	2,748
Change in -
Base rates		41			51			76
Sales growth		48			68			70
Weather		12			(61	)		60
Fuel cost recovery and other		141			42			(3	)

Retail — current year		3,293			3,051			2,951

Sales for resale —
Non-affiliates		484			488			474
Affiliates		308			277			188

Total sales for resale		792			765			662

Other operating revenues		151			144			97

Total operating revenues	$	4,236		$	3,960		$	3,710

Percent change		7.0	%		6.7	%		3.5	%

Retail revenues in 2004 were $3.3 billion. Revenues increased $242 million (7.9 percent) from the prior year, increased $100 million (3.4 percent) in 2003, and increased $203 million (7.4 percent) in 2002. All sectors of retail revenues increased $68 million (3.7 percent) for the Company in 2004. These 2004 and 2003 increases were primarily due to increased fuel revenue and 2.6 percent and 0.8 percent increases in retail base rates which went into effect in July 2003 and July 2004, respectively. See Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for additional information.

The primary contributors to the increase in revenues in 2002 were the positive effect of favorable weather conditions on energy sales and increases in retail base rates (0.6 percent increase in July 2001 and 2 percent increases in both October 2001 and April 2002). The Company mitigated the effect of these increases to customers with a decrease to the energy cost recovery factor in April 2002.

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

Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities. Revenues from power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows:


	2004		2003		2002
	(in thousands)
Unit power -
Capacity	$	134,615	$	130,022	$	119,193
Energy		146,809		145,342		134,051

Total	$	281,424	$	275,364	$	253,244

No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.

Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market based rates that generally provide a margin above the Company’s variable cost to produce

II-76

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

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


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

Total	$	202,415	$	212,092	$	221,046

Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the affiliated company interchange agreements as approved by the Federal Energy Regulatory Commission (FERC). In 2004, sales for resale revenues increased $31 million primarily due to increases in fuel-related expenses. Sales for resale revenues increased $89.1 million in 2003 due to increased capacity payments received from affiliates. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company’s energy cost recovery clause.

Other operating revenues in 2004 increased $7.0 million (4.9 percent) from 2003 due to an increase of $7.7 million in revenues from gas-fueled co-generation steam facilities — primarily as a result of higher gas prices – and a $2.4 million increase in revenues from rent from electric property offset by a $2.0 million decrease in transmission revenues. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.

Other operating revenues in 2003 increased $47 million (48.6 percent) from 2002 due to an increase of $19.4 million in revenues from gas-fueled co-generation steam facilities — primarily as a result of higher gas prices — and a $14.8 million increase in revenues from Alabama Public Service Commission (Alabama PSC) approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002.

The $11 million (9.9 percent) decrease in other operating revenues in 2002 resulted primarily from a $7.0 million decrease in revenues from gas-fueled co-generation steam facilities due to lower gas prices and lower demand.

Energy Sales

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


	KWH		Percent Change
	2004		2004			2003			2002
	(millions)

Residential		17,368		2.4	%		(2.5	)%		9.6	%
Commercial		13,823		2.8			0.7			4.4
Industrial		22,855		5.8			2.3			3.1
Other		198		(2.4	)		(1.1	)		3.7

Total retail		54,244		3.9			0.3			5.5
Sales for resale-
Non-affiliates		15,483		(9.4	)		9.9			1.8
Affiliates		7,234		(23.2	)		6.5			—

Total		76,961		(2.2	)		2.9			4.1

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

In 2003, residential energy sales experienced a 2.5 percent decrease over the prior year and total retail energy sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the previous year. Although retail sales to industrial customers increased 2.3 percent in 2003 and 3.1 percent in 2002, overall sales to industrial customers remained depressed due to the continuing effect of sluggish economic conditions.

Residential energy sales for 2002 experienced a 9.6 percent increase over the prior year and total retail energy sales grew by 5.5 percent primarily as a result of warmer summer temperatures and colder winter weather conditions compared to the previous year.

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

II-77

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

Expenses

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

The total operating expenses in 2003 were approximately $3.0 billion, an increase of $257 million (9.6 percent) over the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an increase in the average cost of natural gas and coal. In addition, purchased power expenses increased a total of $66 million, maintenance expense increased $30 million primarily related to transmission and distribution overhead lines, and depreciation and amortization expense increased $15 million.

In 2002, total operating expenses of $2.7 billion increased by $13 million (0.5 percent) over the previous year. This slight increase was mainly due to a $35 million increase in administrative and general expenses primarily related to employee salaries, insurance expense, and accrued expenses for liability insurance, litigation, and workers compensation, a $19 million increase in production expenses related to boiler plant maintenance, and a $15 million increase in depreciation and amortization expenses due to an increase in depreciable property. These increases were offset by a $43 million decrease in purchased power expenses and a $14 million decrease in fuel expenses related to lower coal prices.

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of fossil and nuclear generating units and hydro generation. The amount and sources of generation and the average cost of fuel per net kilowatt-hour (KWH) generated and the average cost of purchased power were as follows:


	2004		2003		2002

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

Fuel and purchased power expenses totaled $1.6 billion in 2004, an increase of $216 million (15.6 percent). This was due to the average natural gas prices increasing by 30.5 percent, the average coal prices increasing 3.1 percent over the previous year, and higher capacity payments associated with an existing power purchase agreement (PPA). In 2003, total fuel and purchased power expenses of $1.4 billion increased $164 million (13.4 percent) over 2002 due to a 58.3 percent increase in average gas prices and a 2.2 percent increase in average coal prices. Fuel and purchased power expenses in 2002 of $1.2 billion decreased $75 million (5.8 percent) due primarily to lower average fuel cost, while total energy sales increased 3.0 billion KWHs (4.1 percent) compared with the amounts recorded in 2001.

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

Purchased power consists of purchases from affiliates in the Southern Company electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at

II-78

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

each company. Purchased power from non-affiliates increased $75 million (68 percent) in 2004. This was due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices over the previous year. In 2003, purchased power from non-affiliates increased $20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy purchased when compared to 2002. During 2002, purchased power transactions from non-affiliates decreased $54 million (37 percent) due to the addition in May 2001 of a combined cycle unit which generated 6.1 billion KWHs in 2002, an 18.4 percent increase over the previous year.

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

Allowance for equity funds used during construction (AFUDC) increased $3.5 million (28.2 percent) in 2004 due primarily to an increase in the amount of construction work in progress over the prior year. AFUDC increased $1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate. AFUDC increased $4 million (57.5 percent) in 2002 due to an increase in the amount of construction work in progress over the prior year. See Note 1 to the financial statements under “AFUDC” for additional information.

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

Effects of Inflation

The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.

FUTURE EARNINGS POTENTIAL

General

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

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the Company’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly more stringent environmental standards. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.

II-79

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

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

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company was effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final resolution of that appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against the Company, placing the case back onto the court’s active docket. See Note 3 to the financial statements under “New Source Review Actions” for additional information.

The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Alabama in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

II-80

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

Environmental Statutes and Regulations

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. See “FERC and Alabama PSC Matters – Environmental Rate Filing” and Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for additional information. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions and resulted in total construction expenditures of approximately $66 million through 2000. Some of these previous expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Birmingham, Alabama. In December 2000, the Alabama Department of Environmental Management (ADEM) adopted revisions to the state implementation plan for meeting the one-hour ozone standard. These revisions required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near those nonattainment areas. Two plants in the Birmingham area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled approximately $249 million through 2004.

To help attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Alabama, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. Affected sources, including five of the Company’s coal-fired plants, were required to comply with these reductions by May 31, 2004. Additional construction expenditures for compliance with these rules are currently estimated at approximately $369 million, of which $169 million remains to be spent. In March 2004, the EPA redesignated the Birmingham, Alabama area from nonattainment to attainment under the one-hour ozone standard.

In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA’s implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court’s concerns. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. The counties around Birmingham have been designated as nonattainment under the eight-hour ozone standard. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of Alabama’s state implementation plan and therefore cannot be determined at this time.

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

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

II-81

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

ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases – in 2010 and 2015. The EPA currently plans to finalize this rule in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.

The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any change in the Company’s fuel mix, future environmental compliance costs cannot be determined at this time.

Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA’s Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. The Company has a number of plants that could be subject to these rules. The EPA’s Regional Haze program calls for states to submit implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations – a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities. The regulations are scheduled to be finalized by March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with possible additional federal or state legislation or regulations related to global climate change or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company’s operations. The full impact of any such changes cannot, however, be determined at this time.

Global Climate Issues

II-82

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

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

Environmental Remediation Reserves

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. The Company has not incurred any significant cleanup costs to date.

FERC and Alabama PSC Matters

Transmission

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

Generation Interconnection Agreements

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

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as an agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities’ applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found them and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This

II-83

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

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

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

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

Hydro Relicensing

In 2002, the Company initiated the relicensing process for the Company’s seven hydroelectric projects on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and the Smith and Bankhead projects on the Warrior River. The FERC licenses for all of these nine projects expire in 2007. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company. The final outcome of this matter cannot be determined at this time.

Nuclear Relicensing

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

Environmental Rate Filing

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

II-84

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

Retail Rate Adjustments

The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate Certificated New Plant (CNP). Effective July 2003, the Company’s retail rates were adjusted by approximately 2.6% under Rate CNP as a result of two new certificated PPAs that began in June 2003. An additional increase of $25 million annually was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP is expected to decrease retail rates by approximately 0.5 percent, or $18.5 million annually. See Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for additional information.

Retail Fuel Cost Recovery

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

Natural Disaster Cost Recovery

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

The operation and maintenance expenses associated with repairing the damage to the Company’s facilities and restoring service to customers as a result of Hurricane Ivan were $57.8 million for 2004. The balance in the Company’s natural disaster reserve prior to the storm was $14.6 million. On October 19, 2004, the Company received approval from the Alabama PSC to record its hurricane related operation and maintenance expenses in its natural disaster reserve, thereby deferring the regulatory asset for recovery in future periods. The Company is allowed to accrue $250 thousand per month until a maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2004, the Company accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004 the regulatory asset totaled $37.7 million.

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

Income Tax Matters

American Jobs Creation Act of 2004

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

Other Matters

II-85

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

the foreseeable future. Postretirement benefit costs for the Company were $22 million, $23 million, and $23 million in 2004, 2003, and 2002, respectively, and are expected to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Southern Company senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.

Electric Utility Regulation

The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See “FUTURE EARNINGS POTENTIAL” herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:

II-86

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

• Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

• Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

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

New Accounting Standards

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

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

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

II-87

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

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

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

The Company’s ratio of common equity to total capitalization — including short-term debt — was 42.6 percent in 2004, 43.3 percent in 2003, and 42.6 percent in 2002. See Note 6 to the financial statements for additional information.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any financings — if needed — will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt, preferred stock, and preferred securities.

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

The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. In accordance with the Public Utility Holding Company Act of 1935, as amended (PUHCA), most loans between affiliated companies must be approved in advance by the SEC.

The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business.

To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2005, the Company had approximately $84 million of cash and cash equivalents and $868 million of unused credit arrangements with banks. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.

The Company maintains committed lines of credit in the amount of $868 million of which $643 million will expire at various times during 2005. $225 million of the credit facilities expiring in 2005 allow for the execution of term loans for an additional two-year period, and $245 million allow for the execution of one-year term loans. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

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

Financing Activities

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

II-88

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

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


	2004			2003			2002

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

Credit Rating Risk

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

Market Price Risk

Due to cost-based rate regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on outstanding variable long-term debt that has not been hedged at January 1, 2005 was 2.57 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $2.5 million at January 1, 2005. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.

In addition, the Company’s Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company’s electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company’s natural gas budget for that year.

At December 31, 2004, exposure from these activities was not material to the Company’s financial position, results of operations, or cash flows. The fair value changes in energy related derivative contracts and year-end valuations were as follows at December 31:


	Changes in Fair Value

	2004			2003

	(in thousands)
Contracts beginning of year	$	6,413		$	21,402
Contracts realized or settled		(26,384	)		(38,809	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		23,988			23,820

Contracts end of year	$	4,017		$	6,413

(a)

Current period changes also include the changes in fair value of new contracts entered into during the period.


	Source of 2004 Year-End
	Valuation Prices
	Total		Maturity
	Fair Value		2005		2006-2007

	(in thousands)

Actively quoted	$	3,985	$	2,917	$	1,068
External sources		32		32		—
Models and other methods		—		—		—

Contracts end of Year	$	4,017	$	2,949	$	1,068

II-89

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

Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:


	Amounts

	(in thousands)
Regulatory liabilities, net	$	3,978
Other comprehensive income		—
Net income		39

Total fair value	$	4,017

Unrealized pre-tax gains (losses) on energy contracts recognized in income in 2004 and 2003 were not material. For 2002, pre-tax losses of $2.0 million were recognized in income. The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $902 million for 2005, $921 million for 2006, and $1.0 billion for 2007. Over the next three years, the Company estimates spending $913 million on environmental related additions (including $276 million on selective catalytic reduction facilities), $238 million on Plant Farley (including $177 million for nuclear fuel), $767 million on distribution facilities, and $411 million on transmission additions. See Note 7 to the financial statements under “Construction Program” for additional details.

Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

In addition to the funds required for the Company’s construction program, approximately $1.4 billion will be required by the end of 2007 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower-cost capital if market conditions permit.

As a result of requirements by the NRC, the Company has established external trust funds for the purpose of funding nuclear decommissioning costs. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Alabama PSC. The amount expensed in 2004 was $18 million. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Additionally, as discussed in Note 1 to the financial statements under “Fuel Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.

The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over a long period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under “Postretirement Benefits.”

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

II-90

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

Contractual Obligations


			2006-		2008-		After
	2005		2007		2009		2009		Total

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

Total	$	2,675.6	$	5,696.7	$	1,634.1	$	4,791.9	$	14,798.3

(a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2005, as reflected in the statements of capitalization.

(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $947 million, $921 million, and $854 million, respectively.

(d) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.

(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2004.

(f) The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

II-91

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

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

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

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

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

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

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

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

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

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

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

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

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

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

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

II-92

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



	2004			2003			2002

	(in thousands)
Operating Revenues:
Retail sales	$	3,292,828		$	3,051,463		$	2,951,217
Sales for resale —
Non-affiliates		483,839			487,456			474,291
Affiliates		308,312			277,287			188,163
Other revenues		151,012			143,955			96,862

Total operating revenues		4,235,991			3,960,161			3,710,533

Operating Expenses:
Fuel		1,186,472			1,067,821			969,521
Purchased power —
Non-affiliates		186,187			110,885			90,998
Affiliates		226,697			204,353			158,121
Other operations		634,030			611,418			574,979
Maintenance		313,407			309,451			279,406
Depreciation and amortization		425,906			412,919			398,428
Taxes other than income taxes		242,809			228,414			216,919

Total operating expenses		3,215,508			2,945,261			2,688,372

Operating Income		1,020,483			1,014,900			1,022,161
Other Income and (Expense):
Allowance for equity funds used during construction		16,141			12,594			11,168
Interest income		15,677			15,220			13,991
Interest expense, net of amounts capitalized		(193,590	)		(214,302	)		(225,706	)
Interest expense to affiliate trusts		(16,191	)		—			—
Distributions on mandatorily redeemable preferred securities		—			(15,255	)		(24,599	)
Other income (expense), net		(24,728	)		(31,702	)		(28,785	)

Total other income and (expense)		(202,691	)		(233,445	)		(253,931	)

Earnings Before Income Taxes		817,792			781,455			768,230
Income taxes		313,024			290,378			292,436

Net Income		504,768			491,077			475,794
Dividends on Preferred Stock		23,597			18,267			14,439

Net Income After Dividends on Preferred Stock	$	481,171		$	472,810		$	461,355

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

II-93

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



	2004			2003			2002

	(in thousands)
Operating Activities:
Net income	$	504,768		$	491,077		$	475,794
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		497,010			487,370			442,660
Deferred income taxes and investment tax credits, net		252,858			153,154			48,828
Deferred revenues		(11,510	)		(17,932	)		(8,099	)
Allowance for equity funds used during construction		(16,141	)		(12,594	)		(11,168	)
Pension, postretirement, and other employee benefits		(29,362	)		(38,953	)		(34,977	)
Tax benefit of stock options		10,672			8,680			6,670
Other, net		10,817			6,292			19,271
Changes in certain current assets and liabilities —
Receivables, net		(144,256	)		(13,488	)		33,074
Fossil fuel stock		30,130			(13,251	)		25,535
Materials and supplies		(26,229	)		(4,651	)		3,728
Other current assets		19,131			(953	)		1,479
Accounts payable		(12,778	)		77,128			(1,034	)
Accrued taxes		(24,568	)		(33,507	)		(40,922	)
Accrued compensation		(7,041	)		664			17,122
Other current liabilities		(42,544	)		29,058			(4,798	)

Net cash provided from operating activities		1,010,957			1,118,094			973,163

Investing Activities:
Gross property additions		(797,014	)		(661,154	)		(645,262	)
Cost of removal net of salvage		(37,369	)		(35,440	)		(32,111	)
Other		11,575			(1,169	)		5,017

Net cash used for investing activities		(822,808	)		(697,763	)		(672,356	)

Financing Activities:
Increase (decrease) in notes payable, net		—			(36,991	)		26,994
Proceeds —
Senior notes		900,000			1,415,000			975,000
Mandatorily redeemable preferred securities		—			—			300,000
Preferred stock		100,000			125,000			—
Common stock		40,000			50,000			—
Capital contributions from parent company		17,541			17,826			43,118
Redemptions —
First mortgage bonds		—			—			(350,000	)
Senior notes		(725,000	)		(1,507,000	)		(415,602	)
Other long-term debt		(1,445	)		(943	)		(883	)
Mandatorily redeemable preferred securities		—			—			(347,000	)
Preferred stock		—			—			(70,000	)
Payment of preferred stock dividends		(23,639	)		(18,181	)		(14,176	)
Payment of common stock dividends		(437,300	)		(430,200	)		(431,000	)
Other		(16,597	)		(14,775	)		(30,329	)

Net cash used for financing activities		(146,440	)		(400,264	)		(313,878	)

Net Change in Cash and Cash Equivalents		41,709			20,067			(13,071	)
Cash and Cash Equivalents at Beginning of Period		42,752			22,685			35,756

Cash and Cash Equivalents at End of Period	$	84,461		$	42,752		$	22,685

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6,832, $6,367, and $6,738 capitalized, respectively)	$	188,556		$	185,272		$	230,102
Income taxes (net of refunds)		69,068			161,004			269,043

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

II-94

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



Assets	2004			2003

	(in thousands)
Current Assets:
Cash and cash equivalents	$	84,461		$	42,752
Receivables —
Customer accounts receivable		235,221			223,865
Unbilled revenues		96,486			95,953
Under recovered regulatory clause revenues		119,773			16,697
Other accounts and notes receivable		52,145			53,547
Affiliated companies		61,149			48,876
Accumulated provision for uncollectible accounts		(5,404	)		(4,756	)
Fossil fuel stock, at average cost		57,787			86,993
Vacation pay		36,494			35,530
Materials and supplies, at average cost		237,919			211,690
Prepaid expenses		61,896			78,409
Other		11,269			19,454

Total current assets		1,049,196			909,010

Property, Plant, and Equipment:
In service		14,636,168			14,224,117
Less accumulated provision for depreciation		5,097,930			4,907,549

		9,538,238			9,316,568
Nuclear fuel, at amortized cost		93,388			93,611
Construction work in progress		470,844			321,316

Total property, plant, and equipment		10,102,470			9,731,495

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		45,455			47,811
Nuclear decommissioning trusts, at fair value		445,634			384,574
Other		44,322			23,708

Total other property and investments		535,411			456,093

Deferred Charges and Other Assets:
Deferred charges related to income taxes		316,528			321,077
Prepaid pension costs		489,193			446,256
Unamortized debt issuance expense		28,392			23,457
Unamortized loss on reacquired debt		109,403			110,946
Other regulatory assets		46,603			13,092
Other		106,263			91,370

Total deferred charges and other assets		1,096,382			1,006,198

Total Assets	$	12,783,459		$	12,102,796

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

II-95

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



Liabilities and Stockholder’s Equity	2004		2003

	(in thousands)
Current Liabilities:
Securities due within one year	$	225,005	$	526,019
Accounts payable —
Affiliated		141,096		141,940
Other		198,834		162,314
Customer deposits		49,598		47,507
Accrued taxes —
Income taxes		28,498		3,679
Other		29,688		22,274
Accrued interest		40,029		46,489
Accrued vacation pay		36,494		35,530
Accrued compensation		76,858		75,726
Other		26,365		34,407

Total current liabilities		852,465		1,095,885

Long-term Debt (See accompanying statements)		3,855,257		3,377,148

Long-term Debt Payable to Affiliated Trusts (See accompanying statements)		309,279		—

Mandatorily Redeemable Preferred Securities (See accompanying statements)		—		300,000

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		1,885,120		1,684,741
Deferred credits related to income taxes		148,395		162,168
Accumulated deferred investment tax credits		205,353		216,309
Employee benefit obligations		194,837		174,036
Deferred capacity revenues		25,056		36,567
Asset retirement obligations		383,621		358,759
Asset retirement obligation regulatory liability		159,230		127,346
Other cost of removal obligations		597,147		572,816
Miscellaneous regulatory liabilities		55,459		86,323
Other		36,989		37,526

Total deferred credits and other liabilities		3,691,207		3,456,591

Total Liabilities		8,708,208		8,229,624

Cumulative Preferred Stock (See accompanying statements)		465,047		372,512

Common Stockholder’s Equity (See accompanying statements)		3,610,204		3,500,660

Total Liabilities and Stockholder’s Equity	$	12,783,459	$	12,102,796

Commitments and Contingent Matters (See notes)

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

II-96

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



	2004			2003				2004			2003

	(in thousands)						(percent of total)
Long-Term Debt:
Long-term notes payable —
4.875% to 7.125% due 2004	$	—		$	525,000
5.49% due November 1, 2005		225,000			225,000
2.65% to 2.80% due 2006		520,000			520,000
Floating rate (2.09% at 1/1/05) due 2006		195,000			195,000
3.50% to 7.125% due 2007		500,000			200,000
3.125% to 5.375% due 2008		410,000			410,000
Floating rate (2.57% at 1/1/05) due 2009		250,000			—
4.70% to 6.75% due 2010-2039		1,425,000			1,275,000

Total long-term notes payable		3,525,000			3,350,000

Other long-term debt —
Pollution control revenue bonds —
Collateralized:
5.50% due 2024		24,400			24,400
Variable rates (2.01% to 2.16% at 1/1/05) due 2015-2017		89,800			89,800
Non-collateralized:
Variable rates (2.01% to 2.16% at 1/1/05) due 2021-2031		445,940			445,940

Total other long-term debt		560,140			560,140

Capitalized lease obligations		52			1,497

Unamortized debt premium (discount), net		(4,930	)		(8,470	)

Total long-term debt (annual interest requirement — $169.0 million)		4,080,262			3,903,167
Less amount due within one year		225,005			526,019

Long-term debt excluding amount due within one year	$	3,855,257		$	3,377,148				46.8	%		44.7	%

II-97

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



	2004			2003			2004			2003

		(in thousands)						(percent of total)
Long-term Debt Payable to Affiliated Trusts:
4.75% through 2007 due 2042*		103,093			—
5.5% through 2009 due 2042*		206,186			—

Total long-term debt payable to affiliated trusts (annual interest requirement — $16.2 million)		309,279			—			3.8			0.0

Mandatorily Redeemable Preferred Securities:
$1,000 liquidation value due 2042 —
4.75% through 2007*		—			100,000
5.50% through 2009*		—			200,000

Total mandatorily redeemable preferred securities		—			300,000			0.0			4.0

Cumulative Preferred Stock:
$100 par or stated value — 4.20% to 4.92%		47,611			47,512
$25 par or stated value — 5.20% to 5.83%		294,105			200,000
$100,000 stated value — 4.95%		123,331			125,000

Total cumulative preferred stock (annual dividend requirement — $24.3 million)		465,047			372,512			5.6			4.9

Common Stockholder’s Equity:
Common stock, par value $40 per share —		330,000			290,000
Authorized - 15,000,000 shares
Outstanding - 8,250,000 shares in 2004 and 7,250,000 shares in 2003
Paid-in capital		1,955,183			1,927,069
Retained earnings		1,341,049			1,291,558
Accumulated other comprehensive income (loss)		(16,028	)		(7,967	)

Total common stockholder’s equity		3,610,204			3,500,660			43.8			46.4

Total Capitalization	$	8,239,787		$	7,550,320			100.0	%		100.0	%

*The fixed rates thereafter are determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 2.91% and 3.10%, respectively.

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

II-98

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



									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total

	(in thousands)
Balance at December 31, 2001	$	240,000	$	1,850,775		$	1,220,102		$	—		$	3,310,877
Net income after dividends on preferred stock		—		—			461,355			—			461,355
Capital contributions from parent company		—		49,788			—			—			49,788
Other comprehensive income (loss)		—		—			—			(13,417	)		(13,417	)
Cash dividends on common stock		—		—			(431,000	)		—			(431,000	)
Other		—		—			137			—			137

Balance at December 31, 2002		240,000		1,900,563			1,250,594			(13,417	)		3,377,740
Net income after dividends on preferred stock		—		—			472,810			—			472,810
Issuance of common stock		50,000		—			—			—			50,000
Capital contributions from parent company		—		26,506			—			—			26,506
Other comprehensive income (loss)		—		—			—			5,450			5,450
Cash dividends on common stock		—		—			(430,200	)		—			(430,200	)
Other		—		—			(1,646	)		—			(1,646	)

Balance at December 31, 2003		290,000		1,927,069			1,291,558			(7,967	)		3,500,660
Net income after dividends on preferred stock		—		—			481,171			—			481,171
Issuance of common stock		40,000		—			—			—			40,000
Capital contributions from parent company		—		28,213			—			—			28,213
Other comprehensive income (loss)		—		—			—			(8,061	)		(8,061	)
Cash dividends on common stock		—		—			(437,300	)		—			(437,300	)
Other		—		(99	)		5,620			—			5,521

Balance at December 31, 2004	$	330,000	$	1,955,183		$	1,341,049		$	(16,028	)	$	3,610,204

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

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



	2004			2003			2002

	(in thousands)
Net income after dividends on preferred stock	$	481,171		$	472,810		$	461,355

Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(2,482), $(2,301) and $(2,536), respectively		(4,083	)		(3,785	)		(4,172	)
Change in fair value of marketable securities, net of tax of $252		414			—			—
Changes in fair value of qualifying hedges, net of tax of $(4,807), $1,330 and $(6,430), respectively		(7,906	)		2,188			(10,576	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $2,136, $4,285 and $810, respectively		3,514			7,047			1,331

Total other comprehensive income (loss)		(8,061	)		5,450			(13,417	)

Comprehensive Income	$	473,110		$	478,260		$	447,938

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

II-99

NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2004 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Gas (Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies — the Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company — provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power — related to jointly-owned generating facilities, interconnecting transmission lines, or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS — the system service company — provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving customers in Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley.

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

Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the Company is subject to regulation by the FERC and the Alabama Public Service Commission (Alabama PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with Southern Nuclear under which Southern Nuclear operates the Company’s Plant Farley and provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other services with respect to business and operations. Costs for these services amounted to $169 million, $153 million, and $154 million during 2004, 2003, and 2002, respectively.

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

II-100

NOTES (continued)
Alabama Power Company 2004 Annual Report

Southern Company holds a 30 percent ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses. Amounts billed under this agreement totaled approximately $28.7 million, $27.5 million, and $34.5 million in 2004, 2003 and 2002, respectively. In addition, the Company purchases synthetic fuel from AFP for use at several of the Company’s plants. Fuel purchases for 2004, 2003, and 2002 totaled $236.9 million, $209.2 million, and $211.0 million, respectively.

In June 2003, the Company entered into an agreement with Southern Power under which the Company operates and maintains Plant Harris at cost. In 2004 and 2003, the Company billed Southern Power $1.8 million and $0.8 million, respectively, for operation and maintenance. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2004 and 2003 totaled $59.0 million and $41.7 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company in 2004 was $65.7 million and $33.9 million in 2003. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in Other Deferred Charges and Other Assets on the balance sheets at December 31, 2004 and 2003. See Note 3 under “Retail Rate Adjustment Procedures” and Note 7 under “Purchased Power Commitments” for additional information.

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

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

The retail operating companies, including the Company, Southern Power, and Southern Company GAS jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $61 million in 2004, $64 million in 2003, and $63 million in 2002. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Plant Farley Unit 1 and the refueling outage scheduled in 2008 for Plant Farley Unit 2. Construction of an on-site dry spent fuel storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units and can be expanded to provide storage through 2025. See Note 7 under “Construction Program” for additional information.

Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability at December 31, 2004 under this law to be approximately $9 million.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are

II-101

NOTES (continued)
Alabama Power Company 2004 Annual Report

expected to be credited to customers through the ratemaking process.

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


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

Total	$	(413	)	$	(437	)

Notes: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a)   Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.

(b)   Recovered over the remaining life of the original issue which may range up to 50 years.

(c)   Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2008.

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

(e)   Recorded and recovered or amortized as approved by the Alabama PSC.

(f)   Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.

In the event that a portion of the Company’s operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are currently reflected in rates.

Revenues

Energy and other revenues are recognized as services are provided. Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.

The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than 1 percent of revenues.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average life of the related property.

Depreciation and Amortization

Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0 percent in 2004, 3.1 percent in 2003, and 3.2 percent in 2002. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost — together with the cost of removal, less salvage — is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

Asset Retirement Obligations
and Other Costs of Removal

II-102

NOTES (continued)
Alabama Power Company 2004 Annual Report

retirement costs for long-lived assets that the Company does not have a legal obligation to retire, the Company has received accounting guidance from the Alabama PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.

The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facility, Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2004 was $446 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these transmission and distribution assets have not been recorded because no reasonable estimate can be made regarding the timing of the obligations. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

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


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

Balance end of year	$	384	$	359

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has established external trust funds to comply with the NRC’s regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient manner in a diversified mix of equity and fixed income securities. Equity securities typically range from 50 to 75 percent of the funds and fixed income securities from 25 to 50 percent. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that — over time — the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.

Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning, based on the most current study as of December 31, 2004, for Plant Farley were as follows:


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

Total	$	955

II-103

NOTES (continued)
Alabama Power Company 2004 Annual Report

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


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

All of the Company’s decommissioning costs for ratemaking are based on the site study. The Company expects the Alabama PSC to periodically review and adjust, if necessary, the amounts paid into the reserve and deposited into external trusts. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and a trust earnings rate of 7.0 percent.

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

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 8.6 percent in 2004, 9.0 percent in 2003, and 8.2 percent in 2002. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 4.2 percent in 2004, 3.5 percent in 2003, and 3.3 percent in 2002.

Property, Plant, and Equipment

The cost of replacements of property — exclusive of minor items of property — is capitalized. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated refueling costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2004, the Company accrued $22.6 million to the nuclear refueling outage reserve and at December 31, 2004 the reserve balance was a regulatory asset of $0.6 million.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of the regulatory disallowance or by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

II-104

NOTES (continued)
Alabama Power Company 2004 Annual Report

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Natural Disaster Reserve

In accordance with an Alabama PSC order, the Company has established a natural disaster reserve to cover the cost of uninsured damages from major storms to transmission and distribution lines and to generation facilities and other property. The Company is allowed to accrue $250 thousand per month until the maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2004, the Company accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of $37.7 million. See Note 3 under “Natural Disaster Cost Recovery” for further information.

Environmental Cost Recovery

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.

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


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


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

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets or liabilities as appropriate until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.

The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.

II-105

NOTES (continued)
Alabama Power Company 2004 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:
At December 31, 2004	$	4,389	$	4,454
At December 31, 2003		3,903		3,958
Preferred Securities:
At December 31, 2004		—		—
At December 31, 2003		300		305

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

Comprehensive Income

Variable Interest Entities

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

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with Employee Retirement Income Security Act of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. The Company also provides certain non-qualified benefit plans for a selected group of management and highly-compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the Alabama PSC. For the year ended December 31, 2005, postretirement trust contributions are expected to total approximately $25.3 million.

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

Pension Plans

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


	Projected
	Benefit Obligations
	2004			2003
	(in millions)
Balance at beginning of year	$	1,200		$	1,088
Service cost		30			27
Interest cost		71			68
Benefits paid		(64	)		(61	)
Plan amendments		1			3
Actuarial (gain) loss		87			75

Balance at end of year	$	1,325		$	1,200


	Plan Assets
	2004			2003
	(in millions)
Balance at beginning of year	$	1,583		$	1,419
Actual return on plan assets		157			226
Benefits paid		(64	)		(62	)

Balance at end of year	$	1,676		$	1,583

II-106

NOTES (continued)
Alabama Power Company 2004 Annual Report

and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. Southern Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.


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

Total		100	%		100	%		100	%

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


	2004		2003
	(in millions)
Funded status	$	351	$	383
Unrecognized transition amount		—		(5	)
Unrecognized prior service cost		80		87
Unrecognized net (gain) loss		27		(37	)

Prepaid pension asset, net	$	458	$	428

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


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

Prepaid pension asset, net	$	458		$	428

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


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

Net pension cost (income)	$	(36	)	$	(52	)	$	(56	)

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


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

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:


	Accumulated
	Benefit Obligations
	2004			2003
	(in millions)
Balance at beginning of year	$	441		$	405
Service cost		7			6
Interest cost		24			26
Benefits paid		(18	)		(20	)
Actuarial (gain) loss		11			24

Balance at end of year	$	465		$	441


	Plan Assets
	2004			2003
	(in millions)
Balance at beginning of year	$	186		$	158
Actual return on plan assets		24			25
Employer contributions		20			23
Benefits paid		(18	)		(20	)

Balance at end of year	$	212		$	186

II-107

NOTES (continued)
Alabama Power Company 2004 Annual Report


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

Total		100	%		100	%		100	%

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


	2004			2003
	(in millions)
Funded status	$	(253	)	$	(255	)
Unrecognized transition obligation		33			37
Unrecognized prior service cost		68			73
Unrecognized net loss (gain)		87			82
Fourth quarter contributions		9			6

Accrued liability recognized in the balance sheets	$	(56	)	$	(57	)

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


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

Net postretirement cost	$	22		$	23		$	23

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


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


	2004			2003			2002
Discount		5.75	%		6.00	%		6.50	%
Annual salary increase		3.50			3.75			4.00
Long-term return on plan assets		8.50			8.50			8.50

An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2004 as follows:


	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	41	$	32
Service and interest costs		2		2

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6

II-108

NOTES (continued)
Alabama Power Company 2004 Annual Report

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

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against the Company cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.

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

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

Since the inception of the NSR proceedings against the Company, Georgia Power, and Savannah Electric, the EPA has also been proceeding with similar NSR enforcement actions against other utilities, involving many of the same legal issues. In each case, the EPA alleged that the utilities failed to comply with the NSR permitting requirements when performing maintenance and construction activities at coal-burning plants, which activities the utilities considered to be routine or otherwise not subject to NSR. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

II-109

NOTES (continued)
Alabama Power Company 2004 Annual Report

In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the State of Alabama in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Generation Interconnection Agreements

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

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities’ applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found them and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

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

II-110

NOTES (continued)
Alabama Power Company 2004 Annual Report

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

Natural Disaster Cost Recovery

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

Retail Regulatory Matters

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

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

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

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

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

4. JOINT OWNERSHIP AGREEMENTS

The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice. The Company’s share of purchased power totaled $86 million in 2004, $87 million in 2003, and $84 million in 2002 and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method on the balance sheets.

In addition the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse

II-111

NOTES (continued)
Alabama Power Company 2004 Annual Report

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

At December 31, 2004, the capitalization of SEGCO consisted of $59 million of equity and $88 million of debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $12.0 million in 2004, $2.3 million in 2003, and $5.8 million in 2002, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO’s net income.

In addition to the Company’s ownership of SEGCO, the Company’s percentage ownership and investment in jointly-owned generating plants at December 31, 2004 is as follows:


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

(1)		Jointly owned with an affiliate, Mississippi Power.

(2)		Jointly owned with Alabama Electric Cooperative, Inc.


	Company		Accumulated
Facility	Investment		Depreciation
	(in millions)
Greene County	$	114	$	56
Plant Miller Units 1 and 2		776		356

The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners. The Company’s proportionate share of its plant operating expenses is included in operating expenses in the statements of income.

5. INCOME TAXES

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

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

At December 31, 2004, the Company’s tax-related regulatory assets and liabilities were $317 million and $148 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

Details of the income tax provisions are as follows:


	2004		2003		2002
	(in millions)
Total provision for income taxes:
Federal —
Current	$	44	$	111	$	209
Deferred		219		137		41

		263		248		250

State —
Current		16		26		35
Deferred		34		16		7

		50		42		42

Total	$	313	$	290	$	292

II-112

NOTES (continued)
Alabama Power Company 2004 Annual Report


	2004			2003
	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	1,524		$	1,319
Property basis differences		461			466
Premium on reacquired debt		45			46
Pensions		136			128
Fuel clause under recovered		48			—
Other		36			29

Total		2,250			1,988

Deferred tax assets:
Federal effect of state deferred taxes		112			100
State effect of federal deferred taxes		110			98
Pole attachment rentals		45			27
Unbilled revenue		22			23
Pension and other benefits		16			15
Fuel clause over recovered		—			2
Other		32			72

Total		337			337

Total deferred tax liabilities, net		1,913			1,651
Portion included in current (liabilities) assets, net		(28	)		34

Accumulated deferred income taxes in the balance sheets	$	1,885		$	1,685

In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $11 million in each of 2004, 2003, and 2002. At December 31, 2004, all investment tax credits available to reduce federal income taxes payable had been utilized.

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:


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

Effective income tax rate		38.3	%		37.2	%		38.1	%

6. FINANCING

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

The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $309 million, which constitute substantially all assets of these trusts and are reflected on the balance sheets as Long-term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2004, preferred securities of $300 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

First Mortgage Bonds

The Company has a firm power sales contract with the Alabama Municipal Electric Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts) for a period through October 2006. Under the terms of the contract, the Company received payments from AMEA representing the net present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate of 11.19 percent. These payments are being recognized as operating revenues and the discount is amortized to other interest expense as scheduled capacity is made available over the terms of the contract.

To secure AMEA’s advance payments and the Company’s performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the Company occurs. As the liquidated damages decline, a portion of the bond equal to the decrease is returned to the Company. At December 31, 2004, $18.7 million of these bonds were held by the escrow agent under the contract.

II-113

NOTES (continued)
Alabama Power Company 2004 Annual Report

Pollution Control Bonds

Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.

Senior Notes and Preferred Stock

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

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

Long-Term Debt Due Within One Year

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


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

Total	$	225	$	526

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

Assets Subject to Lien

The Company’s mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company’s fixed property and franchises.

Bank Credit Arrangements

The Company maintains committed lines of credit in the amount of $868 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $643 million will expire at various times during 2005. $225 million of the credit facilities expiring in 2005 allow for the execution of term loans for an additional two-year period, and $245 million allow for the execution of one-year term loans. All of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees are less than 1/4 of 1 percent for the Company. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit arrangements, a fee is also paid to the agent banks.

Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65 percent of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2004, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings.

The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company borrows from time to time through extendible commercial note programs. As of December 31, 2004 and 2003, the Company had no extendible commercial notes and no commercial paper outstanding. During 2004, the peak amount outstanding for commercial paper was $190 million and the average amount outstanding was $41.5 million. The average annual interest rate on commercial paper in 2004 was 1.51 percent. Commercial paper and extendible commercial notes are included in notes payable on the balance sheets.

At December 31, 2004, the Company had regulatory approval to have outstanding up to $1 billion of short-term borrowings.

II-114

NOTES (continued)
Alabama Power Company 2004 Annual Report

Financial Instruments

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:


	Amounts
	(in thousands)
Regulatory liabilities, net	$	3,978
Net income		39

Total fair value	$	4,017

The fair value gain or loss for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place through 2007.

The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

At December 31, 2004, the Company had $981 million notional amount of interest rate swaps outstanding with net fair value losses of $7.2 million as follows:

Cash Flow Hedges


	Weighted Average				Fair
	Fixed				Value
	Rate		Notional		Gain/
Maturity	Paid		Amount		(Loss)
			(in millions)
2006		1.89	$	195	$	3.2
2007		2.01*		536		5.6
2035		5.68		250		(16.0	)

Hedged using the Bond Market Association Municipal Swap Index.

The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2004 and 2003, the Company settled gains (losses) of $5.5 million and $(8) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the underlying related debt.

For the years 2004, 2003 and 2002, approximately $6.3 million, $11.3 million, and $2.1 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, pre-tax gains of approximately $0.7 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2035.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $902 million in 2005, $921 million in 2006, and $1.0 billion in 2007. These amounts include $24 million, $12 million, and $11 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.

II-115

NOTES (continued)
Alabama Power Company 2004 Annual Report

Long-Term Service Agreements

The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs stipulate that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $253 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2004, the remaining balance was approximately $193 million. However, the LTSAs contain various cancellation provisions at the option of the Company.

Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

Purchased Power Commitments

The Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2004 were as follows:


	Commitments
			Non-
Year	Affiliated		Affiliated		Total
	(in millions)
2005	$	50	$	37	$	87
2006		50		37		87
2007		50		38		88
2008		50		39		89
2009		50		40		90
2010 and thereafter		13		25		38

Total commitments	$	263	$	216	$	479

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2004. Total estimated minimum long-term commitments at December 31, 2004 were as follows:


			Coal &
	Natural		Nuclear
Year	Gas		Fuel
	(in millions)
2005	$	249	$	907
2006		195		804
2007		114		713
2008		26		225
2009		26		131
2010 and thereafter		108		97

Total commitments	$	718	$	2,877

Additional commitments for fuel will be required to supply the Company’s future needs.

SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.

Operating Leases

The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $28.3

II-116

NOTES (continued)
Alabama Power Company 2004 Annual Report

million in 2004, $29.5 million in 2003, and $29.6 million in 2002. Of these amounts, $16.3 million, $19.4 million, and $19.1 million for 2004, 2003, and 2002, respectively, relates to the rail car leases and are recoverable through the Company’s Rate ECR clause. At December 31, 2004, estimated minimum rental commitments for noncancellable operating leases were as follows:


	Rail		Vehicles
Year	Cars		& Other		Total
	(in millions)
2005	$	17.7	$	11.4	$	29.1
2006		14.1		8.6		22.7
2007		6.9		5.7		12.6
2008		6.6		4.0		10.6
2009		4.8		3.6		8.4
2010 and thereafter		27.4		7.2		34.6

Total minimum payments	$	77.5	$	40.5	$	118.0

In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2006 and 2009, and the Company’s maximum obligations are $66 million and $19.5 million, respectively. At the termination of the leases, at the Company’s option, the Company may negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company’s payments under the residual value obligations.

Guarantees

At December 31, 2004, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets. See “Operating Leases” above.

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2004, 1,111 current and former employees of the Company participated in this stock option plan. The maximum number of shares of Southern Company common stock that may be issued under the plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below:


	Shares			Average
	Subject			Option Price
	to Option			per Share

Balance at December 31, 2001		5,201,605		$	17.56
Options granted		1,332,716			25.26
Options canceled		(12,515	)		22.59
Options exercised		(827,883	)		15.03

Balance at December 31, 2002		5,693,923			19.72
Options granted		1,201,677			27.98
Options canceled		(6,726	)		23.11
Options exercised		(1,043,013	)		16.16

Balance at December 31, 2003		5,845,861			22.05
Options granted		1,168,140			29.50
Options canceled		(3,379	)		28.82
Options exercised		(1,252,277	)		18.07

Balance at December 31, 2004		5,758,345			24.42



Options exercisable:
At December 31, 2002		2,702,614
At December 31, 2003		3,171,383
At December 31, 2004		3,404,264

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


	Dollar Price
	Range of Options
	13-20		20-26		26-32
Outstanding:
Shares (in thousands)		1,386		2,032		2,340
Average remaining life (in years)		5.7		6.8		8.6
Average exercise price	$	17.56	$	24.12	$	28.74
Exercisable:
Shares (in thousands)		1,386		1,609		409
Average exercise price	$	17.56	$	23.83	$	28.00

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act of 1988 (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $10.76 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by

II-117

NOTES (continued)
Alabama Power Company 2004 Annual Report

American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $100.5 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $201 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Act expired in August 2002; however, the indemnity provisions of the act remain in place for commercial nuclear reactors.

The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.

Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL and has elected a 12 week waiting period.

Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $39 million.

Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all “non-certified” terrorist acts, (i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA)). The NEIL aggregate, applies to non-certified claims stemming from terrorism within a 12 month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI cap is a $300 million shared industry aggregate. Any act of terrorism that is certified pursuant to the TRIA will not be subject to the foregoing NEIL and ANI limitations but will be subject to the TRIA annual aggregate limitation of $100 billion of insured losses arising from certified acts of terrorism. The TRIA will expire on December 31, 2005.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2004 and 2003 are as follows:


					Net Income
					After
					Dividends
Quarter	Operating		Operating		on Preferred
Ended	Revenues		Income		Stock
	(in millions)
March 2004	$	960	$	202	$	91
June 2004		1,059		239		104
September 2004		1,246		415		220
December 2004		971		164		66

March 2003	$	890	$	211	$	92
June 2003		950		227		107
September 2003		1,216		414		217
December 2003		904		163		57

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

II-118

SELECTED FINANCIAL AND OPERATING DATA 2000-2004
Alabama Power Company 2004 Annual Report



	2004		2003		2002		2001		2000

Operating Revenues (in thousands)	$	4,235,991	$	3,960,161	$	3,710,533	$	3,586,390	$	3,667,461
Net Income after Dividends on Preferred Stock (in thousands)	$	481,171	$	472,810	$	461,355	$	386,729	$	419,916
Cash Dividends on Common Stock (in thousands)	$	437,300	$	430,200	$	431,000	$	393,900	$	417,100
Return on Average Common Equity (percent)		13.53		13.75		13.80		11.89		13.58
Total Assets (in thousands)	$	12,783,459	$	12,102,796	$	11,591,666	$	11,303,605	$	11,228,118
Gross Property Additions (in thousands)	$	797,014	$	661,154	$	645,262	$	635,540	$	870,581

Capitalization (in thousands):
Common stock equity	$	3,610,204	$	3,500,660	$	3,377,740	$	3,310,877	$	3,195,772
Preferred stock		465,047		372,512		247,512		317,512		317,512
Mandatorily redeemable preferred securities		—		300,000		300,000		347,000		347,000
Long-term debt payable to affiliated trusts		309,279		—		—		—		—
Long-term debt		3,855,257		3,377,148		2,872,609		3,742,346		3,425,527

Total (excluding amounts due within one year)	$	8,239,787	$	7,550,320	$	6,797,861	$	7,717,735	$	7,285,811

Capitalization Ratios (percent):
Common stock equity		43.8		46.4		49.7		42.9		43.9
Preferred stock		5.6		4.9		3.6		4.1		4.4
Mandatorily redeemable preferred securities		—		4.0		4.4		4.5		4.8
Long-term debt payable to affiliated trusts		3.8		—		—		—		—
Long-term debt		46.8		44.7		42.3		48.5		46.9

Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0

Security Ratings:
First Mortgage Bonds -
Moody’s		A1		A1		A1		A1		A1
Standard and Poor’s		A		A		A		A		A
Fitch		AA-		A+		A+		A+		AA-
Preferred Stock -
Moody’s		Baa1		Baa1		Baa1		Baa1		a2
Standard and Poor’s		BBB+		BBB+		BBB+		BBB+		BBB+
Fitch		A		A-		A-		A-		A
Unsecured Long-Term Debt -
Moody’s		A2		A2		A2		A2		A2
Standard and Poor’s		A		A		A		A		A
Fitch		A+		A		A		A		A+

Customers (year-end):
Residential		1,170,814		1,160,129		1,148,645		1,139,542		1,132,410
Commercial		208,547		204,561		203,017		196,617		193,106
Industrial		5,260		5,032		4,874		4,728		4,819
Other		753		757		789		751		745

Total		1,385,374		1,370,479		1,357,325		1,341,638		1,331,080

Employees (year-end):		6,745		6,730		6,715		6,706		6,871

II-119

SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Alabama Power Company 2004 Annual Report



	2004		2003		2002		2001		2000

Operating Revenues (in thousands):
Residential	$	1,346,669	$	1,276,800	$	1,264,431	$	1,138,499	$	1,222,509
Commercial		980,771		913,697		882,669		829,760		854,695
Industrial		948,528		844,538		788,037		763,934		859,668
Other		16,860		16,428		16,080		15,480		15,835

Total retail		3,292,828		3,051,463		2,951,217		2,747,673		2,952,707
Sales for resale — non-affiliates		483,839		487,456		474,291		485,974		461,730
Sales for resale — affiliates		308,312		277,287		188,163		245,189		166,219

Total revenues from sales of electricity		4,084,979		3,816,206		3,613,671		3,478,836		3,580,656
Other revenues		151,012		143,955		96,862		107,554		86,805

Total	$	4,235,991	$	3,960,161	$	3,710,533	$	3,586,390	$	3,667,461

Kilowatt-Hour Sales (in thousands):
Residential		17,368,321		16,959,566		17,402,645		15,880,971		16,771,821
Commercial		13,822,926		13,451,757		13,362,631		12,798,711		12,988,728
Industrial		22,854,399		21,593,519		21,102,568		20,460,022		22,101,407
Other		198,253		203,178		205,346		198,102		205,827

Total retail		54,243,899		52,208,020		52,073,190		49,337,806		52,067,783
Sales for resale — non-affiliates		15,483,420		17,085,376		15,553,545		15,277,839		14,847,533
Sales for resale — affiliates		7,233,880		9,422,301		8,844,050		8,843,094		5,369,474

Total		76,961,199		78,715,697		76,470,785		73,458,739		72,284,790

Average Revenue Per Kilowatt-Hour (cents):
Residential		7.75		7.53		7.27		7.17		7.29
Commercial		7.10		6.79		6.61		6.48		6.58
Industrial		4.15		3.91		3.73		3.73		3.89
Total retail		6.07		5.84		5.67		5.57		5.67
Sales for resale		3.49		2.88		2.72		3.03		3.11
Total sales		5.31		4.85		4.73		4.74		4.95
Residential Average Annual Kilowatt-Hour Use Per Customer		14,894		14,688		15,198		13,981		14,875
Residential Average Annual Revenue Per Customer	$	1,155	$	1,106	$	1,104	$	1,002	$	1,084
Plant Nameplate Capacity Ratings (year-end) (megawatts)		12,216		12,174		12,153		12,153		12,122
Maximum Peak-Hour Demand (megawatts):
Winter		9,556		10,409		9,423		9,300		9,478
Summer		10,938		10,462		10,910		10,241		11,019
Annual Load Factor (percent)		63.2		64.1		62.9		62.5		59.3
Plant Availability (percent):
Fossil-steam		87.8		85.9		85.8		87.1		89.4
Nuclear		88.7		94.7		93.2		83.7		88.3

Source of Energy Supply (percent):
Coal		56.5		56.5		55.5		56.8		63.0
Nuclear		16.4		17.0		17.1		15.8		16.9
Hydro		5.6		7.0		5.1		5.1		2.9
Gas		8.9		7.6		11.6		10.7		4.9
Purchased power -
From non-affiliates		5.4		4.1		4.0		4.4		4.6
From affiliates		7.2		7.8		6.7		7.2		7.7

Total		100.0		100.0		100.0		100.0		100.0

II-120

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Georgia Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (a wholly owned subsidiary of Southern Company) as of December 31, 2004 and 2003, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of Georgia Power Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements (pages II-143 to II-173) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

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

II-122

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

OVERVIEW

Business Activities

Georgia Power Company (Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges and risks of the Company’s primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. In 2004, the Company completed a major retail rate proceeding that should help provide future earnings stability. This regulatory action will also enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.

Key Performance Indicators

The Company strives to maximize shareholder value while providing low-cost energy to more than 2 million customers by focusing on several key indicators. These include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring that satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by the investment community and many regulatory agencies.

The Company’s 2004 results compared to its targets for each of these indicators are reflected in the following chart.

2004

Target

Actual

Key Performance Indicator

Performance

Customer Satisfaction

Top quartile performance on
national surveys

Top quartile

Peak Season EFOR

2.90% or less

0.81

ROE

13.70

13.95

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

Earnings

The Company’s 2004 earnings totaled $658 million representing a $27 million (4.3 percent) increase over 2003. Operating income increased in 2004 due to higher base retail revenues attributable to more favorable weather and customer growth during the year, partially offset by higher non-fuel operating expenses. In addition, lower depreciation and amortization expense in the final year of a Georgia Public Service Commission (PSC) retail rate plan that was effective January 2002 (2001 Retail Rate Plan) significantly offset increased purchased power capacity expenses. The Company’s 2003 earnings totaled $631 million, representing a $13 million (2.1 percent) increase over 2002. Operating income increased in 2003 despite lower base retail revenues resulting from the extremely mild summer weather. Higher wholesale revenues and lower non-fuel operating expenses contributed to the increase. The Company’s 2002 earnings totaled $618 million, representing an $8 million (1.2 percent) increase over 2001 resulting from lower financing costs and a lower effective tax rate due to the realization of certain state tax credits. Operating income declined slightly in 2002. Lower retail and wholesale revenues, higher other operating and maintenance expenses, and increased purchased power capacity expenses were significantly offset by lower depreciation and amortization expense as a result of the 2001 Retail Rate Plan.

II-123

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

RESULTS OF OPERATIONS

A condensed income statement for the Company is as follows:


				Increase (Decrease)
	Amount			From Prior Year
	2004			2004			2003			2002
	(in millions)
Operating revenues	$	5,371		$	457		$	92		$	(144	)

Fuel		1,233			128			101			64
Purchased power		976			200			92			(87	)
Other operation and maintenance		1,400			153			(78	)		85
Depreciation and amortization		275			(74	)		(54	)		(197	)
Taxes other than income taxes		228			15			11			(1	)

Total operating expenses		4,112			422			72			(136	)

Operating income		1,259			35			20			(8	)
Total other income and (expense)		(221	)		5			2			9
Income taxes		379			13			9			(7	)

Net income		659			27			13			8
Dividends on preferred stock		1			—			—			—

Net income after dividends on preferred stock	$	658		$	27		$	13		$	8

Revenues

Operating revenues in 2004, 2003, and 2002 and the percent of change from the prior year are as follows:


	Amount
	2004			2003			2002
	(in millions)
Retail — prior year	$	4,310		$	4,288		$	4,349
Change in -
Base rates		—			—			(118	)
Sales growth and other		151			30			2
Weather		32			(66	)		82
Fuel cost recovery and other		284			58			(27	)

Retail — current year		4,777			4,310			4,288

Sales for resale -
Non-affiliates		247			260			271
Affiliates		166			175			98

Total sales for resale		413			435			369

Other operating revenues		181			169			165

Total operating revenues	$	5,371		$	4,914		$	4,822

Percent change		9.3	%		1.9	%		(2.9	)%

Retail base revenues of $3.2 billion in 2004 increased by $183 million (6.0 percent) from 2003 primarily due to an improved economy, customer growth, generally higher prices to the Company’s large business customers, and more favorable weather. Retail base revenues of $3 billion in 2003 decreased by $36 million (1.2 percent) from 2002 primarily due to extremely mild summer temperatures in 2003 and the sluggish economy. Retail base revenues of $3.1 billion in 2002 decreased by $34 million (1.1 percent) from 2001 primarily due to a base rate reduction effective January 2002 under the 2001 Retail Rate Plan and generally lower prices to large business customers.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses — including the fuel component of purchased energy — and do not affect net income. In August 2003, the Georgia PSC issued an order allowing the Company to increase customer fuel rates to recover existing under recovered deferred fuel costs. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs. On February 18, 2005, the Company filed a

II-124

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

request with the Georgia PSC for a fuel cost recovery rate increase. In the ordinary course, these new rates will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the Company asked that the Georgia PSC accept the new rate, effective April 1, 2005, prior to a formal hearing on the Company’s request. This action, if taken by the Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, but will not preclude the Georgia PSC from subsequently adjusting the rates. The requested increase, representing an annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. The Company’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine the Company’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time. See Note 3 to the financial statements under “Fuel Cost Recovery” for further information regarding this filing.

Wholesale revenues from sales to non-affiliated utilities were:


	2004		2003		2002
	(in millions)
Unit power sales —
Capacity	$	31	$	34	$	34
Energy		33		31		34
Other power sales —
Capacity		75		93		62
Energy		108		102		141

Total	$	247	$	260	$	271

Revenues from unit power sales contracts remained relatively constant in 2004. Revenues from unit power contracts decreased slightly in 2003 due to decreased energy sales. Revenues from other non-affiliated sales decreased $12 million (6.2 percent), $8 million (3.9 percent), and $102 million (33.4 percent) in 2004, 2003, and 2002, respectively, primarily due to fluctuations in off-system sale transactions that were generally offset by corresponding purchase transactions. These transactions had no significant effect on income. In 2002, revenues also decreased $37 million as a result of transferring Plant Dahlberg to Southern Power Company (Southern Power) in July 2001.

Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the affiliate company interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC). In 2004, kilowatt-hour (KWH) energy sales to affiliates decreased 18.2 percent due to lower demand. However, the decline in associated revenues was only 4.9 percent due to higher fuel prices. In 2003, KWH energy sales to affiliates increased 47.5 percent due to the combination of increased demand by Southern Power to meet contractual obligations and the availability of power due to milder-than-normal weather in the Company’s service territory. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other operating revenues increased $11.7 million (6.9 percent) in 2004 primarily due to higher revenues from outdoor lighting of $4.2 million and pole attachment rentals of $4.9 million and higher gains on sales of emission allowances of $2 million. Other operating revenues increased $4 million (2.4 percent) in 2003 primarily due to an increase in the open access transmission tariff rate, which increased revenues $7 million, and higher revenues from increased customer demand for outdoor lighting services of $4 million, partially offset by lower revenues from the rental of electric property of $4 million. Other operating revenues in 2002 increased $14 million (9.5 percent) primarily due to the collection of new late payment fees approved under the 2001 Retail Rate Plan of $7 million and higher revenues from increased customer demand for outdoor lighting services of $5 million and the transmission of electricity of $3 million.

II-125

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

Energy Sales

KWH sales for 2004 and the percent change by year were as follows:


	KWH		Percent Change
	2004		2004			2003			2002
	(in billions)
Residential		22.9		5.3	%		(1.7	)%		10.1	%
Commercial		28.0		4.0			(0.1	)		1.7
Industrial		26.4		2.5			(0.1	)		1.5
Other		0.6		1.1			0.4			1.7

Total retail		77.9		3.8			(0.5	)		4.0

Sales for resale -
Non-affiliates		6.0		(32.5	)		9.5			(0.5	)
Affiliates		4.8		(18.2	)		47.5			26.5

Total sales for resale		10.8		(26.8	)		22.0			7.0

Total sales		88.7		(1.2	)		2.6			4.4

Residential KWH sales increased 5.3 percent in 2004 due to more favorable weather and a 1.9 percent increase in residential customers. Commercial KWH sales increased 4.0 percent in 2004 due to an improved economy and a 2.8 percent increase in commercial customers. Industrial sales increased 2.5 percent in 2004 due to the improved economy. Residential KWH sales decreased 1.7 percent in 2003 due to the effect of the milder summer weather, despite the 2.0 percent increase in residential customers. Commercial KWH sales in 2003 declined slightly due to the milder summer weather, while industrial KWH sales declined slightly due to the sluggish economy. Residential KWH sales increased 10.1 percent in 2002 due to the effect of the warmer weather. Commercial and industrial KWH sales in 2002 increased 1.7 percent and 1.5 percent, respectively, due to corresponding increases of 2.6 percent and 2.4 percent, respectively, in customers. Retail sales growth assuming normal weather is expected to be 1.9 percent on average from 2005 to 2009.

Expenses

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation, the average cost of fuel per net KWH generated, and the average cost of purchased power per net KWH were as follows:


	2004		2003		2002
Total generation (billions of KWH)		71.5		73.1		70.4
Sources of generation (percent) —
Coal		75.4		75.4		77.4
Nuclear		22.5		21.6		21.1
Hydro		2.0		2.7		1.2
Oil and gas		0.1		0.3		0.3
Average cost of fuel per net KWH generated (cents) —		1.55		1.46		1.42
Average cost of purchased power per net KWH (cents) —		5.17		4.03		3.29

Fuel expense increased 11.6 percent in 2004 primarily due to an increase in the average cost of fuel. Fuel expense increased 10.1 percent in 2003 due to an increase in generation of 3.9 percent because of higher wholesale energy demands and a 2.8 percent higher average cost of fuel due to the higher prices of coal and natural gas in 2003. Fuel expense increased 6.8 percent in 2002 due to a 2.2 percent increase in generation because of higher energy demands and a 2.9 percent higher average cost of fuel due to the higher cost of coal.

Purchased power expense increased $200 million (25.9 percent) in 2004 primarily due to a 38.5 percent increase in the average cost of fuel per net KWH and $65 million of additional capacity expense associated with new purchased power agreements (PPAs) between the Company and Southern Power that went into effect in June 2004 and June 2003. Purchased power expense increased $92 million (13.3 percent) in 2003 primarily due to $75 million of additional capacity expense associated with new PPAs between the Company and Southern Power that went into effect in 2003 and 2002. Purchased power expense decreased $87 million (11.2 percent) in 2002 primarily due to fluctuations in off-system energy purchases used to meet off-system sales commitments. The 2002 decrease in energy purchases was partially offset by a $43 million increase in capacity expense associated with new PPAs between the Company and Southern Power.

II-126

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 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 slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions.

In 2004, other operation and maintenance expenses increased $153 million (12.3 percent) due to the timing of generating plant maintenance of $39 million and transmission and distribution maintenance of $39 million. Increased employee benefit expense of $30 million related to pension and medical benefits and higher workers compensation expense of $8 million also contributed to the increase. In 2003, other operation and maintenance expenses decreased $78 million (5.9 percent) due to the timing of generating plant maintenance of $46 million and transmission and distribution maintenance of $8 million and lower severance costs of $8 million. In 2002, other operation and maintenance expenses increased $85 million (6.8 percent) due to the timing of generating plant maintenance of $44 million and transmission maintenance of $17 million and increased property insurance expense of $5 million.

Depreciation and amortization decreased $74 million and $54 million in 2004 and 2003, respectively, primarily as a result of the amortization of a regulatory liability related to the inclusion of new certified PPAs in retail rates on a levelized basis as ordered by the Georgia PSC. Depreciation and amortization decreased $197 million in 2002 primarily as a result of discontinuing accelerated depreciation, beginning amortization of the regulatory liability for accelerated cost recovery, and lowering the composite depreciation rates as part of the 2001 Retail Rate Plan. See Note 3 to the financial statements under “Retail Rate Orders” for additional information.

Taxes other than income taxes increased $15 million (7.0 percent) in 2004 due to higher municipal gross receipts taxes associated with increased operating revenues. Taxes other than income taxes increased $11 million (5.4 percent) in 2003 due mainly to a favorable true-up of state property tax valuations in 2002. Taxes other than income taxes remained relatively constant in 2002.

Allowance for equity funds used during construction increased $15.9 million in 2004 primarily due to the Company’s acquisition of the Plant McIntosh combined cycle Units 10 and 11 construction project from Southern Power. See FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters” and Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information.

Interest income decreased $9 million in 2004 and increased $12 million in 2003 when compared to the prior year primarily due to interest on a favorable income tax settlement of $14.5 million in 2003. Interest income remained relatively constant in 2002.

Interest expense remained relatively constant in 2004. Interest expense increased in 2003 primarily due to an increase in senior notes outstanding that was partially offset by a reduction in short-term debt outstanding. Interest expense decreased in 2002 primarily due to lower interest rates that offset new financing costs. The Company refinanced or retired $400 million, $665 million, and $929 million of securities in 2004, 2003, and 2002, respectively. Interest capitalized increased in 2004 due to the Plant McIntosh construction project referenced above and decreased in 2003 and 2002 due to the transfer of three generation projects to Southern Power in 2002 and 2001. See Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information regarding the Plant McIntosh construction project.

Other income and (expense), net decreased in 2004 primarily due to the $13 million disallowance of Plant McIntosh construction costs pursuant to a Georgia PSC order issued on December 21, 2004 (2004 Retail Rate Plan), partially offset by a $7.5 million decrease in donations and $3.4 million in increased income from a customer pricing program. See Note 3 to the financial

II-127

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

statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information on the disallowance.

Effects of Inflation

The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preferred stock, and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated company providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the southeastern United States. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and revenues are reviewed and adjusted periodically within certain limitations based on earned ROE. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Rate Orders” and “Market-Based Rate Authority” for additional information about this and other regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to recover costs related to growing demand, to achieve energy sales growth while containing costs, and to meet increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company was effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the case pending against the Company. At this time, no party to the case against the Company has sought to reopen the case, which remains administratively closed in the U.S.

II-128

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

District Court for the Northern District of Georgia. See Note 3 to the financial statements under “New Source Review Actions” for additional information.

The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this case could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. The December 2002 revisions included changes to the regulatory exclusions and the methods of calculating emissions increases. The October 2003 regulations clarified the scope of the existing Routine Maintenance, Repair, and Replacement (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Georgia in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential rulemakings by the State of Georgia cannot be determined at this time.

Plant Wansley Environmental Litigation

On December 30, 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against the Company for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the Court ruling in favor of the Company in part and the plaintiffs in part. The Company has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate remedy trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. See Note 3 to the financial statements under “Plant Wansley Environmental Litigation” for additional information. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could result in substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

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

II-129

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

Environmental Statutes and Regulations

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. The Title IV acid rain provisions of the Clean Air Act, for example, required significant reductions in sulfur dioxide and nitrogen oxide emissions and resulted in total construction expenditures of approximately $206 million through 2000. Some of these previous expenditures also assisted the Company in complying with nitrogen oxide emission reduction requirements under Title I of the Clean Air Act, which were designed to address one-hour ozone nonattainment problems in Atlanta, Georgia. The State of Georgia adopted regulations that required additional nitrogen oxide emission reductions from May through September of each year at plants in and/or near nonattainment areas. Seven generating plants in the Atlanta area are currently subject to those requirements, the most recent of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide emission reduction requirements totaled $687.2 million through 2004, with an additional $6 million committed through 2007.

To help attain the one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required 21 states, including Georgia, to reduce and cap nitrogen oxide emissions from power plants and other large industrial sources. As a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements could be applied in Georgia. In April 2004, the EPA published final regional nitrogen oxide reduction rules applicable to Georgia, specifying a May 1, 2007 compliance date. However, in October 2004, the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the nitrogen oxide reduction rules will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of Georgia’s state implementation plan and cannot be determined at this time.

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

In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These revisions made the standards significantly more stringent and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. In the subsequent litigation of these standards, the U.S. Supreme Court found the EPA’s implementation program for the new eight-hour ozone standard unlawful and remanded it to the EPA for further rulemaking. During 2003, the EPA proposed implementation rules designed to address the court’s concerns. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour standard. Areas within the Company’s service territory that have been designated as nonattainment under the eight-hour ozone standard include Macon, Georgia and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005, and that areas classified as “severe” nonattainment areas under the one-hour standard, such as Atlanta, will not be required to impose emissions fees if those areas fail to come into attainment with the one-hour standard. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

II-130

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

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

In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and nitrogen oxide emission reductions from power plants in the eastern United States in two phases – in 2010 and 2015. The EPA currently plans to finalize this rule in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard, the eight-hour ozone standard, and other air quality regulations. The impact of this rule on the Company will depend upon the specific requirements of the final rule and cannot be determined at this time.

Further reductions in sulfur dioxide and nitrogen oxides could also be required under the EPA’s Regional Haze rules. The Regional Haze rules require states to establish Best Available Retrofit Technology (BART) standards for certain sources that contribute to regional haze and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. The Company has a number of plants that could be subject to these rules. The EPA’s Regional Haze program calls for states to submit implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

In January 2004, the EPA issued proposed rules regulating mercury emissions from electric utility boilers. The proposal solicits comments on two possible approaches for the new regulations – a Maximum Achievable Control Technology approach and a cap-and-trade approach. Either approach would require significant reductions in mercury emissions from Company facilities. The regulations are scheduled to be finalized by March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

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

II-131

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

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

Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with possible additional federal or state legislation or regulations related to global climate change or other environmental and health concerns could also significantly affect the Company. The impact of any new legislation, changes to existing legislation, or environmental regulations could affect many areas of the Company’s operations. The full impact of any such changes cannot, however, be determined at this time.

Global Climate Issues

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

Environmental Remediation Reserves

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up and monitor known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Remediation” for additional information.

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

FERC and Georgia PSC Matters

Transmission

II-132

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

an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” herein for additional information. The final outcome of these proceedings cannot now be determined. However, the Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with the Company and another Southern Company subsidiary, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities, with interest. The Company has opposed such relief and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In November 2001, the FERC modified the test it uses to consider utilities’ applications to charge market-based rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to several utilities, including Southern Company, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

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

II-133

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

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

Retail Rate Case

On December 21, 2004, the Georgia PSC approved the 2004 Retail Rate Plan for the three-year period ending December 31, 2007. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated annually against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates will be increased by approximately $194 million and customer fees will be increased by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability.

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

Plant McIntosh Construction Project

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

As directed by the Georgia PSC order, in June 2004, the Company and Savannah Electric filed an application to amend the resource certificate granted by the Georgia PSC in 2002 to change the character of the resource from a PPA to a self-owned, rate based asset and to describe the approximate construction schedule and the proposed rate base treatment. In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance, of which $13 million is attributable to the Company, and reduced the Company’s net income by approximately $8 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will be reflected in the Company’s rates evenly over the three years ending 2007. See Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information.

Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets herein. On February 18, 2005, the Company filed a request with the Georgia PSC for a fuel cost recovery rate increase. In the ordinary course, these

II-134

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

new rates will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the Company asked that the Georgia PSC accept the new rate, effective April 1, 2005, prior to a formal hearing on the Company’s request. This action, if taken by the Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, but will not preclude the Georgia PSC from subsequently adjusting the rates. The requested increase, representing an annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. The Company’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine the Company’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time. See Note 3 to the financial statements under “Fuel Cost Recovery” for further information regarding this filing.

Storm Damage Cost Recovery

During the month of September 2004, the Company’s service territory was impacted by Hurricanes Frances, Ivan and Jeanne. The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. The total amount of damage related to these hurricanes was estimated to be approximately $15 million and was charged to the storm damage reserve in 2004. These costs are expected to be recovered through regular monthly accruals which total $6.3 million annually under the 2004 Retail Rate Plan. See Note 3 to the financial statements under “Retail Rate Orders” for additional information.

Other Matters

In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $35 million, $54 million, and $59 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. The decline in pension income is expected to continue and to become an expense by as early as 2007. Postretirement benefit costs for the Company were $44 million, $41 million and $43 million in 2004, 2003, and 2002, respectively, and are expected to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. For the Company, pension income or expense and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

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

The Company is involved in various other matters being litigated, regulatory matters, and related issues that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

II-135

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

Electric Utility Regulation

The Company is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation, which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislative, judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:

•   Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.

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

•   Identification of additional sites that require environmental remediation or the filing of other complaints in which the Company may be asserted to be a potentially responsible party.

•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

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

II-136

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

New Accounting Standards

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

In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $5 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $72 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Over the last several years, the Company’s financial condition has remained stable with emphasis on cost control measures combined with significantly lower costs of capital, achieved through the refinancing and/or redemption of higher-cost securities. Cash flow from operations decreased $219 million resulting primarily from the increase in under recovered deferred fuel costs.

In 2004, gross utility plant additions were $1.1 billion. These additions were primarily related to the construction of Plant McIntosh Units 10 and 11, transmission and distribution facilities, and the purchase of nuclear fuel and equipment to comply with environmental standards. The majority of funds needed for gross property additions for the last several years have been provided from operating activities and capital contributions from Southern Company. The statements of cash flows provide additional details.

The Company’s ratio of common equity to total capitalization — including short-term debt — was 47.7 percent in 2004 and 48.3 percent in 2003 and 2002. See Note 6 to the financial statements for additional information.

Sources of Capital

The Company expects to meet future capital requirements primarily using funds generated from operating activities and capital contributions from

II-137

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

Southern Company and by the issuance of new debt securities, term loans, and short-term borrowings. The type and timing of future financings will depend on market conditions and regulatory approval of additional financing authority. Recently, the Company has relied on the issuance of unsecured securities to meet its long-term external financing requirements.

The issuance of securities by the Company is subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA), and by the Georgia PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company. In accordance with the PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

To meet short-term cash needs and contingencies, the Company had approximately $773.1 million of unused credit arrangements with banks at the beginning of 2005. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefits of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. As of December 31, 2004, the Company had outstanding $208 million of commercial paper and no extendible commercial notes.

At the beginning of 2005, the Company had not used any of its available credit arrangements. Bank credit arrangements are as follows:


			Expires
Total	Unused		2005			2006		2007
			(in millions)
$773.1	$	773.1		$	423.1	—	$	350

The credit arrangements that expire in 2005 allow for the execution of term loans for an additional two-year period.

Financing Activities

During 2004, the Company issued $806 million of long-term debt including long-term debt payable to affiliated trusts. The issuances were used to refund $400 million of long-term debt, as well as to finance the Company’s purchase of the Plant McIntosh construction project from Southern Power. The remainder was used to reduce short-term debt and fund the Company’s ongoing construction program.

Subsequent to December 31, 2004, the Company has issued $250 million of securities with the proceeds used to fund the February 2005 maturity of floating rate senior notes.

Credit Rating Risk

II-138

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

maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $247 million. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company had no material exposure related to these agreements.

Market Price Risk

Due to cost-based regulations, the Company has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.

To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated as hedges. The weighted average interest rate on outstanding variable long-term debt that has not been hedged at January 1, 2005 was 2.04 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $8 million at January 1, 2005. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

The Company has implemented a fuel hedging program at the instruction of the Georgia PSC. Fair value of changes in energy-related derivative contracts and year-end valuations were as follows at December 31:


	Changes in Fair Value
	2004			2003
	(in millions)
Contracts beginning of year	$	3.2		$	0.1
Contracts realized or settled		(12.2	)		(0.4	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		14.8			3.5

Contracts end of year	$	5.8		$	3.2

(a) Current period changes also include the changes in fair value of new contracts entered into during the period.


	Source of 2004 Year-End Valuation Prices
	Total		Maturity
	Fair Value		Year 1		1-3 Years
			(in millions)
Actively quoted	$	4.8	$	3.8	$	1.0
External sources		1.0		1.0		—
Models and other methods methods		—		—		—

Contracts end of year	$	5.8	$	4.8	$	1.0

Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery mechanism. See Note 3 to the financial statements for information regarding the retail fuel hedging program. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:


	Amounts
	(in millions)
Regulatory liabilities, net	$	5.7
Other comprehensive income		—
Net income		0.1

Total fair value	$	5.8

Unrealized gains (losses) recognized in income in 2004, 2003, and 2002 were not material. The Company

II-139

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

is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $911 million for 2005, $1.1 billion for 2006, and $1.2 billion for 2007. Environmental expenditures included in these amounts are $127 million, $284 million, and $506 million for 2005, 2006, and 2007, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

The Company currently has under construction Plant McIntosh Units 10 and 11 scheduled for completion in June 2005. In addition, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet the environmental standards previously discussed, are ongoing.

As a result of requirements by the Nuclear Regulatory Commission, the Company has established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also as discussed in Note 1 to the financial statements under “Fuel Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities.

In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC.

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

II-140

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

Contractual Obligations


			2006-		2008-		After
	2005		2007		2009		2009		Total
					(in millions)
Long-term debt ^(a) —
Principal	$	452	$	456	$	282	$	3,942	$	5,132
Interest		232		426		387		4,283		5,328
Preferred stock dividends^(b)		1		1		1		—		3
Operating leases		32		52		42		63		189
Purchase commitments^(c) —
Capital ^(d)		911		2,277		2,571		—		5,759
Coal and nuclear fuel		1,731		2,722		771		96		5,320
Natural gas^(e)		248		388		389		1,669		2,694
Purchased power		339		692		673		1,222		2,926
Long-term service agreements		6		19		22		150		197
Trusts^(f) —
Nuclear decommissioning		9		14		14		124		161
Postretirement benefits		8		24		—		—		32
DOE assessments		3		4		—		—		7

Total	$	3,972	$	7,075	$	5,152	$	11,549	$	27,748

(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $1.4 billion, $1.2 billion, and $1.3 billion, respectively.

(d) The Company forecasts capital expenditures over a five-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.

(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on New York Mercantile Exchange future prices at December 31, 2004.

(f) Projections of nuclear decommissioning trust contributions are based on the 2004 Retail Rate Plan. The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

II-141

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

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

• variations in demand for electricity, including those relating to weather, the general economy and population, and business growth (and declines);