The Southern Company (SO) 10-K 2005 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from      to

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-3526	The Southern Company	58-0690070
	(A Delaware Corporation)
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000
1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18th Street
	Birmingham, Alabama 35291
	(205) 257-1000
1-6468	Georgia Power Company	58-0257110
	(A Georgia Corporation)
	241 Ralph McGill Boulevard, N.E.
	Atlanta, Georgia 30308
	(404) 506-6526
0-2429	Gulf Power Company	59-0276810
	(A Florida Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111
001-11229	Mississippi Power Company	64-0205820
	(A Mississippi Corporation)
	2992 West Beach
	Gulfport, Mississippi 39501
	(228) 864-1211
1-5072	Savannah Electric and Power Company	58-0418070
	(A Georgia Corporation)
	600 East Bay Street
	Savannah, Georgia 31401
	(912) 644-7171
333-98553	Southern Power Company	58-2598670
	(A Delaware Corporation)
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000

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

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

Title of each class		Registrant
Common Stock, $5 par value		The Southern Company
Mandatorily redeemable preferred securities, $25 liquidation amount
7.125% Trust Preferred Securities2
Class A preferred, cumulative, $25 stated capital		Alabama Power Company
5.20% Series	5.83% Series
5.30% Series
Senior Notes
5 5/8% Series AA
Senior Notes		Georgia Power Company
5.90% Series O	6% Series R	5.70% Series X
5.75% Series T	6% Series W
Mandatorily redeemable preferred securities, $25 liquidation amount
7 1/8% Trust Preferred Securities3
5 7/8% Trust Preferred Securities4
Senior Notes		Gulf Power Company
5.25% Series H	5.75% Series I
5.875% Series J
Mandatorily redeemable preferred securities, $25 liquidation amount
7.375% Trust Preferred Securities5

1	As of December 31, 2005.
2	Issued by Southern Company Capital Trust VI and guaranteed by The Southern Company.
3	Issued by Georgia Power Capital Trust V and guaranteed by Georgia Power Company.
4	Issued by Georgia Power Capital Trust VII and guaranteed by Georgia Power Company.
5	Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company.

Senior Notes	Mississippi Power Company
5 5/8% Series E
Depositary preferred shares, each representing one-fourth of a share of preferred stock, cumulative, $100 par value
5.25% Series
Mandatorily redeemable preferred securities, $25 liquidation amount
7.20% Trust Originated Preferred Securities6
___________________________________
Preferred stock, non-cumulative, $25 par value                                                 Savannah Electric and Power Company
6% Series
Senior Notes
5.75% Series G

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

Title of each class			Registrant
Preferred stock, cumulative, $100 par value			Alabama Power Company
4.20% Series	4.60% Series	4.72% Series
4.52% Series	4.64% Series	4.92% Series
Class A Preferred Stock, cumulative, $100,000 stated capital
Flexible Money Market (Series 2003A)
___________________________________
Preferred stock, cumulative, $100 stated value			Georgia Power Company
$4.60 Series (1954)8
___________________________________
Preference stock, non-cumulative, $100 par value			Gulf Power Company
6.000% Series
___________________________________
Preferred stock, cumulative, $100 par value			Mississippi Power Company
4.40% Series	4.60% Series
4.72% Series
___________________________________

6	Issued by Mississippi Power Capital Trust II and guaranteed by Mississippi Power Company.
7	As of December 31, 2005.
8	This series was redeemed in January 2006.

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of
the Act. Yes ___Noþ (Response applicable to all registrants.)

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

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

	Large
	Accelerated	Accelerated	Non-accelerated
Registrant	Filer	Filer	Filer
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Gulf Power Company			X
Mississippi Power Company			X
Savannah Electric and Power Company			X
Southern Power Company			X

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yeso Noþ (Response applicable to all registrants.)

     Aggregate market value of The Southern Company’s common stock held by non-affiliates of The Southern Company at June 30, 2005: $25.9 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant’s common stock follows:

	Description of	Shares Outstanding
Registrant	Common Stock	at January 31, 2006
The Southern Company	Par Value $5 Per Share		741,738,001
Alabama Power Company	Par Value $40 Per Share		9,250,000
Georgia Power Company	Without Par Value		7,761,500
Gulf Power Company	Without Par Value		992,717
Mississippi Power Company	Without Par Value		1,121,000
Savannah Electric and Power Company	Par Value $5 Per Share		10,844,635
Southern Power Company	Par Value $0.01 Per Share		1,000

     Documents incorporated by reference: specified portions of The Southern Company’s Proxy Statement relating to the 2006 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Information Statements of Alabama Power Company and Mississippi Power Company relating to each of their respective 2006 Annual Meetings of Shareholders are incorporated by reference into PART III.

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

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

Table of Contents

		Page
	PART I
Item 1	Business	I-1
	The SOUTHERN System	I-2
	Construction Programs	I-4
	Financing Programs	I-5
	Fuel Supply	I-5
	Territory Served by the Utilities	I-6
	Competition	I-9
	Regulation	I-10
	Rate Matters	I-12
	Employee Relations	I-14
Item 1A	Risk Factors	I-16
Item 1B	Unresolved Staff Comments	I-25
Item 2	Properties	I-26
Item 3	Legal Proceedings	I-29
Item 4	Submission of Matters to a Vote of Security Holders	I-30
	Executive Officers of Southern Company	I-31
	Executive Officers of Alabama Power	I-33
	Executive Officers of Mississippi Power	I-34
	PART II
Item 5	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	II-1
Item 6	Selected Financial Data	II-2
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	II-2
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	II-3
Item 8	Financial Statements and Supplementary Data	II-4
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	II-5
Item 9A	Controls and Procedures	II-6
Item 9B	Other Information	II-6
	PART III
Item 10	Directors and Executive Officers of the Registrants	III-1
Item 11	Executive Compensation	III-8
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	III-18
Item 13	Certain Relationships and Related Transactions	III-20
Item 14	Principal Accountant Fees and Services	III-22
	PART IV
Item 15	Exhibits and Financial Statement Schedules	IV-1
	Signatures	IV-2

 i

DEFINITIONS

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

Term	Meaning
AEC	Alabama Electric Cooperative, Inc.
AFUDC	Allowance for Funds Used During Construction
Alabama Power	Alabama Power Company
AMEA	Alabama Municipal Electric Authority
Clean Air Act	Clean Air Act Amendments of 1990
Dalton	City of Dalton, Georgia
DOE	United States Department of Energy
Energy Act of 1992	Energy Policy Act of 1992
Energy Act of 2005	Energy Policy Act of 2005
Energy Solutions	Southern Company Energy Solutions, Inc.
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FMPA	Florida Municipal Power Agency
FP&L	Florida Power & Light Company
Gas South	Gas South, LLC, an affiliate of Cobb Electric Membership Corporation
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
Hampton	City of Hampton, Georgia
Holding Company Act	Public Utility Holding Company Act of 1935, as amended
IBEW	International Brotherhood of Electrical Workers
IIC	Intercompany Interchange Contract
IPP	Independent power producer
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
JEA	Jacksonville Electric Authority
KUA	Kissimmee Utility Authority
MEAG	Municipal Electric Authority of Georgia
Mirant	Mirant Corporation
Mississippi Power	Mississippi Power Company
Moody’s	Moody’s Investors Service
NRC	Nuclear Regulatory Commission
OPC	Oglethorpe Power Corporation
OUC	Orlando Utilities Commission
PPA	Power Purchase Agreement
Progress Energy	Florida Power Corporation, d/b/a Progress Energy Florida, Inc.
PSC	Public Service Commission
registrants	The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Savannah Electric and Power Company and Southern Power Company
retail operating companies	Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company

 ii

DEFINITIONS
(continued)

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

 iii

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION

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

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Act of 2005, and also changes in environmental, tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

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

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

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

The registrants expressly disclaim any obligation to update any forward-looking statements.

 iv

PART I

Item 1. BUSINESS

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

Alabama Poweris 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 Powerwas 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 Poweris a Florida corporation that has had a continuous existence since it was originally organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under the laws of the State of Florida on November 2, 2005.

Mississippi Powerwas 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 Electricis a corporation existing under the laws of the State of Georgia; its charter was granted by the Secretary of State on August 5, 1921. On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement, under which Savannah Electric will merge with and into Georgia Power, with Georgia Power as the surviving corporation in the merger. Following the merger, Southern Company will continue to own all of the outstanding common stock of Georgia Power. The merger must be approved by the shareholders of Savannah Electric and the sole shareholder of Georgia Power, and is subject to receipt of related regulatory approvals of the FERC, Georgia PSC and Federal Communications Commission. Assuming the timely receipt of all required approvals, Georgia Power and Savannah Electric expect to complete the merger by July 2006. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Retail Regulatory Matters — Merger” in Item 8 herein for additional information.

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

     Southern Company also owns all the outstanding common stock or membership interests of SouthernLINC Wireless, Southern Company Gas, Southern Nuclear, SCS, Southern Telecom, Southern Holdings and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Company Gas, which began operation in August 2002, was a competitive retail natural gas marketer which served communities in Georgia until January 4, 2006 when it sold substantially all of its assets to Gas South (see “The SOUTHERN System – Other

I-1

Business” herein for additional information). Southern Nuclear provides services to Alabama Power’s and Georgia Power’s nuclear plants. SCS is the system service company providing, at cost, specialized services to Southern Company and its subsidiary companies. Southern Telecom provides wholesale fiber optic solutions to telecommunication providers in the Southeastern United States. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses.

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

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

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

The SOUTHERN System

Retail Operating Companies

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

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

     The IIC provides for coordinating operations of the power producing facilities of the retail operating companies and Southern Power and the capacities available to such companies from non-affiliated sources and for the pooling of surplus energy available for interchange. Coordinated operation of the entire interconnected system is conducted through a central power supply coordination office maintained by SCS. The available sources of energy are allocated to the retail operating companies and Southern Power to provide the most economical sources of power consistent with reliable operation. The resulting benefits and savings are apportioned among each of the companies. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters — Intercompany Interchange Contract” of each of the registrants in Item 7 herein, Note 3 to the financial statements of Southern Company and each of the retail operating companies and Note 2 to the financial statements of Southern Power, all under “FERC Matters — Intercompany Interchange

I-2

Contract” in Item 8 herein for information on the FERC proceeding related to the IIC.

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

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

Southern Power

Southern Power is an electric wholesale generation subsidiary with market-based rate authority from the FERC. Southern Power constructs, owns and manages generating facilities and sells the output under long-term, fixed-price capacity contracts both to unaffiliated wholesale purchasers as well as to the retail operating companies (under PPAs approved by the respective state PSCs). Southern Power’s business activities are not subject to traditional state regulation of utilities but are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation and electric transmission risks by making such risks the responsibility of the counterparties to the PPAs. However, Southern Power’s overall profit will depend on the parameters of the wholesale market and its efficient operation of its wholesale generating assets. At December 31, 2005, Southern Power had 5,403 megawatts of generating capacity in commercial operation.

Other Business

On January 4, 2006, Southern Company Gas completed the sale of substantially all of its assets, including natural gas inventory, accounts receivable and customer list to Gas South. See Note 3 to the financial statements of Southern Company under “Southern Company Gas Sale” in Item 8 herein for additional information.

     Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses.

     SouthernLINC Wireless serves Southern Company’s retail operating companies and marketing its services to non-affiliates within the Southeast. SouthernLINC Wireless bundles multiple communication options into one phone including InstantLINC^SM Mobile to Mobile, cellular service, text messaging, wireless internet access and wireless data. Its system covers approximately 128,000 square miles in the Southeast.

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

I-3

Construction Programs

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2006 through 2008, see Note 7 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric and Note 6 to the financial statements of Southern Power all under “Construction Program” in Item 8 herein.

     Estimated construction costs in 2006 are expected to be apportioned approximately as follows: (in millions)

	Southern
	Company		Alabama		Georgia		Gulf		Mississippi		Savannah		Southern
	System*		Power		Power		Power		Power		Electric		Power
New generation	$	127	$	—	$	—	$	—	$	—	$	—	$	127
Other generating facilities, including associated plant substations		1,110		458		533		72		23		9		15
New business		356		143		156		26		20		11		—
Transmission		450		104		296		15		24		11		—
Joint line and substation		5		—		—		5		—		—		—
Distribution		284		127		97		15		33		12		—
Nuclear fuel		153		58		95		—		—		—		—
General plant		288		61		74		30		26		2		20
	$	2,773	$	951	$	1,251	$	163	$	126	$	45	$	162

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

     The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment and materials; and cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

     Under Georgia law, Georgia Power and Savannah Electric each are required to file an IRP for approval by the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the construction of new power plants and new PPAs. See “Rate Matters — Integrated Resource Planning” herein for additional information.

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

I-4

Financing Programs

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

Fuel Supply

The retail operating companies’ and SEGCO’s supply of electricity is derived predominantly from coal. Southern Power’s supply of electricity is primarily fueled by natural gas. The sources of generation for the years 2003 through 2005 are shown below:

	Coal		Nuclear		Hydro		Gas		Oil
	%		%		%		%		%
Alabama Power
2003		64		19		8		9		*
2004		65		19		6		10		*
2005		67		19		6		8		*
Georgia Power
2003		75		22		3		*		*
2004		76		22		2		*		*
2005		75		19		2		3		1
Gulf Power
2003		87		**		**		13		*
2004		84		**		**		16		*
2005		86		**		**		14		*
Mississippi Power
2003		74		**		**		26		*
2004		69		**		**		31		*
2005		70		**		**		30		*
Savannah Electric
2003		94		**		**		4		2
2004		96		**		**		3		1
2005		79		**		**		20		1
SEGCO
2003		100		**		**		*		*
2004		100		**		**		*		*
2005		100		**		**		*		*
Southern Power
2003		**		**		**		99		1
2004		**		**		**		100		*
2005		**		**		**		100		*
Southern Company system — weighted average
2003		71		16		4		9		*
2004		69		16		3		12		*
2005		71		15		3		11		*

*	Less than 0.5%.
**	Not applicable.

     For the retail operating companies and SEGCO, the average costs of fuel in cents per net kilowatt-hour generated for 2003 through 2005 are shown below:

	2003		2004		2005
Alabama Power		1.54		1.69		2.02
Georgia Power		1.46		1.55		2.04
Gulf Power		2.11		2.32		2.77
Mississippi Power		1.96		2.50		3.11
Savannah Electric		2.40		2.62		4.15
SEGCO		1.54		1.60		1.69
Southern Company system — weighted average		1.67		1.89		2.39

     The retail operating companies have long-term agreements in place from which they expect to receive approximately 84% of their coal burn requirements in 2006. These agreements cover remaining terms up to 8 years. In 2005, the weighted average sulfur content of all coal burned by the retail operating companies was 0.8% sulfur. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the retail operating companies to remain within limits set by the Phase II acid rain requirements of the Clean Air Act. In 2005, Southern Company purchased approximately $121 million in sulfur dioxide and nitrogen oxide emission allowances. As additional environmental regulations are proposed that impact the utilization of coal, the retail operating companies’ fuel mix will be monitored to ensure that the retail operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the retail operating companies will continue to evaluate the need to purchase additional emission allowances and the timing of capital expenditures for emission control equipment. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations” of Southern Company and each of the retail operating companies in Item 7 herein for information on the Clean Air Act.

     The Southern Company system has long-term agreements in place for its natural gas burn requirements.

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For 2006, the Southern Company system has contracted for 130 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 13 years. In addition to gas supply, the Southern Company system has contracts in place for both firm gas transportation and storage. Management believes that these contracts provide sufficient natural gas supplies, transportation and storage to ensure normal operations of the Southern Company system’s natural gas generating units.

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

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

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

     The Energy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants, including Alabama Power and Georgia Power. This assessment is being paid over a 15-year period ending in 2006. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. See Note 1 to the financial statements of Southern Company, Alabama Power and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 herein for additional information.

Territory Served by the Utilities

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

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

     Georgia Power is engaged in the generation and purchase of electricity and the transmission, distribution and sale of such electricity within the State of Georgia at retail in over 600 communities, as well as in rural areas, and at wholesale currently to OPC, MEAG, Dalton and Hampton. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Merger” in Item 8 herein for information on the planned merger of Savannah Electric with and into Georgia Power.

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

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

     Savannah Electric is engaged, within a five-county area in eastern Georgia, in the generation and purchase of electricity and the distribution and sale of such electricity at retail. See Note 3 to the financial statements of Southern Company under “Merger of Georgia Power and Savannah Electric” and Note 3 to the financial statements of Georgia Power and Savannah Electric under “Merger” in Item 8 herein for information on the planned merger of Savannah Electric with and into Georgia Power.

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

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

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

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

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

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

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

     There are 43 electric cooperative organizations operating in, or in areas adjoining, territory in the State of Georgia in which Georgia Power provides electric service at retail or wholesale. Three of these organizations obtain their power from TVA, one from Southern Power under a 15-year agreement which began in January 2005 and one from other sources. OPC has a wholesale power contract with the remaining 38 of these cooperative organizations. OPC and these cooperative organizations utilize self-owned generation, some of

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which is acquired and jointly-owned with Georgia Power, megawatt capacity purchases from Georgia Power under power supply agreements and other arrangements to meet their power supply obligations. Georgia Power, OPC and Georgia Systems Operations Corporation entered into a new control area compact agreement effective March 1, 2005 which replaced previous coordination service agreements.

     Pursuant to an agreement entered into in April 1999, OPC will purchase 250 megawatts of capacity from Georgia Power through March 2006. In April 2006, AEC will begin purchasing such capacity for a 10-year term. In January 2005, 29 electric cooperative organizations served by OPC and one served by Southern Power began purchasing a total of 700 megawatts of capacity from Georgia Power under individual contracts for 10-year terms. Also, in January 2005, the electric cooperative served by Southern Power began purchasing 25 megawatts of peaking capacity from Georgia Power under a 10-year contract. This electric cooperative will purchase 50 megawatts of coal-fired capacity from Georgia Power beginning April 1, 2006 and ending December 31, 2014 and another 75 megawatts of coal-fired capacity from Georgia Power beginning June 1, 2010 and ending December 31, 2019. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

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

     AMEA was organized under an act of the Alabama legislature and is comprised of 11 municipalities. In October 1991, Alabama Power entered into a power sales contract with AMEA entitling AMEA to scheduled amounts of additional capacity (up to a maximum 80 megawatts) for a period of 15 years. Under the terms of the contract, Alabama Power received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements. This contract expired on December 31, 2005. See Note 6 to the financial statements of Alabama Power under “First Mortgage Bonds” in Item 8 herein for further information on this contract.

     In December 2001, Alabama Power entered into a power sales agreement with AMEA which began on January 1, 2006. Under this contract, AMEA supplies 70 to 95 megawatts of power from its combustion turbine plant and Alabama Power serves the remainder of its member needs through 2010. Beginning in 2011, the amount of power supplied to AMEA by Alabama Power is fixed at 2010 levels and AMEA has the option to seek other suppliers for its incremental growth needs through 2015, at which time the contract terminates.

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

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

     See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Power Sales Agreements” of Southern Power in Item 7 herein for information concerning its PPAs.

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

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

     Under and subject to the provisions of its franchises and concessions and the 1973 State Territorial Electric Service Act, Savannah Electric has the full but nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale, Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee Island, Springfield, Thunderbolt and Vernonburg, and in conjunction with a secondary supplier, the Town of Richmond Hill. In addition, Savannah Electric has been assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and Screven Counties by the Georgia PSC. See “Competition” herein for additional information. In connection with the proposed merger with Savannah Electric, Georgia Power has filed an application with the Georgia PSC for approval of the transfer of Savannah Electric’s service territory to Georgia Power at the effective time of merger.

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

Competition

The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Act of 1992. The Energy Act of 1992 allowed IPPs to access a utility’s transmission network in order to sell electricity to other utilities.

     Alabama Power currently has cogeneration contracts in effect with 11 industrial customers. Under the terms of these contracts, Alabama Power purchases excess generation of such companies. During 2005, Alabama Power purchased approximately 137 million kilowatt-hours from such companies at a cost of $5.7 million.

     Georgia Power currently has contracts in effect with 10 small power producers whereby Georgia Power purchases their excess generation. During 2005, Georgia Power purchased 22 million kilowatt-hours from such companies at a cost of $0.9 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2005, Georgia Power purchased 238 million kilowatt-hours at a cost of $68 million from these facilities.

     Gulf Power currently has agreements in effect with various industrial, commercial and qualifying facilities pursuant to which Gulf Power

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purchases “as available” energy from customer-owned generation. During 2005, Gulf Power purchased 17 million kilowatt-hours from such companies for approximately $0.9 million.

     Mississippi Power currently has a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2005, Mississippi Power purchased approximately 39 million kilowatt-hours of excess generation at a cost of approximately $1 million.

     During 2005, Savannah Electric purchased energy from seven customer-owned generating facilities. Six of the seven customers provide only energy to Savannah Electric. These six customers make no capacity commitment and are not dispatched by Savannah Electric. Savannah Electric does have a contract with the remaining customer for eight megawatts of dispatchable capacity and energy. During 2005, Savannah Electric purchased a total of 62.3 million kilowatt-hours from the seven suppliers at a cost of approximately $3.3 million.

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

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

Regulation

State Commissions

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

Federal Power Act

In July 2005, the U.S. Congress passed the Energy Act of 2005 which repealed the Holding Company Act effective February 8, 2006. The retail operating companies, Southern Power and its generation subsidiaries and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and therefore remain subject to the rate, financial and accounting jurisdiction of the FERC under the Federal Power Act. Certain financing approvals which would have been obtained from the SEC under the repealed Holding Company Act now must be obtained from the FERC. In implementing repeal of the Holding Company Act, the FERC sought to minimize unnecessary administrative burdens and decided to retain an “at cost standard” for services rendered by system service companies such as SCS, to permit certain existing financing authorizations to remain effective without further action by the FERC and to reduce reporting requirements. In addition to its repeal of the Holding Company Act, the Energy Act of 2005 authorized the FERC to establish regional reliability organizations authorized to enforce reliability standards, established a process for the FERC to address impediments to the construction of transmission and established clear responsibility for the FERC to prohibit manipulative energy trading practices.

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

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generating stations having an aggregate installed capacity of 1,074,696 kilowatts.

     In December 2004, the FERC issued a new 30-year license for the Middle Chattahoochee Project. This project consists of the Goat Rock, Oliver and North Highlands facilities. In 2003, Georgia Power started the relicensing process for the Morgan Falls project and is currently working on completing field studies for the facility. The license for the Morgan Falls project expires in 2009. In July 2005, Alabama Power filed two applications with the FERC for a new 50-year license for its seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan and Bouldin) and a new 50-year license for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine developments expire in 2007. In 2006, Alabama Power will initiate the process of developing a relicensing application for the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license will have to be submitted to the FERC in 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters — Hydro Relicensing” of Alabama Power in Item 7 herein for additional information.

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

     Licenses for all projects, excluding those discussed above, expire in the period 2013-2033 in the case of Alabama Power’s projects and in the period 2014-2039 in the case of Georgia Power’s projects.

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

Atomic Energy Act of 1954

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

     The NRC operating licenses for Plant Vogtle units 1 and 2 currently expire in January 2027 and February 2029, respectively. In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of the unit 1 and 2 until 2034 and 2038, respectively. Similarly, in May 2005 the NRC granted Alabama Power a 20-year extension of the licenses for both units at Plant Farley which permits operation of units 1 and 2 until 2037 and 2041, respectively.

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

FERC Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters” of each of the registrants in Item 7 herein for information on matters regarding the FERC.

Environmental Statutes and Regulations

Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water and land resources. Compliance with these environmental requirements involves significant costs, a major portion of which is expected to be recovered through existing ratemaking provisions. There is no assurance, however, that all such costs will, in fact, be recovered.

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

     Additionally, each retail operating company and SEGCO has incurred costs for environmental remediation of various sites. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulation — Environmental Remediation” of Southern Company and each of the retail operating companies in Item 7 herein for information regarding environmental remediation efforts. Also, see Note 3 to the financial statements of Southern Company, Georgia Power and Mississippi Power under “Environmental Matters — Environmental Remediation” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Remediation” in Item 8 herein for information regarding the identification of sites that may require environmental remediation.

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

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

Rate Matters

Rate Structure

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

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

     See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters” of Southern Company and each of the retail operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” and Note 3 to the financial statements of each of the retail operating companies under “Retail Regulatory Matters” in Item 8 herein for a discussion of rate matters. Also, see Note 1 to the financial statements of Southern Company and each of the retail operating companies in Item 8 herein for a discussion of recovery of fuel costs and environmental compliance costs through rates.

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Integrated Resource Planning

Georgia Power and Savannah Electric must file IRPs with the Georgia PSC that specify how each intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC must certify any new demand-side or supply-side resources. Once certified, the lesser of actual or certified construction costs and purchased power costs will be recoverable through rates.

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

     In December 2002, the Georgia PSC certified a PPA between Duke Energy and Georgia Power for 620 megawatts for seven years that began in June 2005.

     In May 2004, the Georgia PSC ordered Georgia Power and Savannah Electric to purchase the McIntosh combined cycle generating facility from Southern Power and place it into their respective rate bases. The McIntosh resource was previously certified as a PPA by the Georgia PSC in the supply-side certification conducted in 2002 and, at the same time, the Georgia PSC also approved the de-certification of Savannah Electric’s Plant Riverside, units 4 through 8, effective in May 2005. The McIntosh units produce a combined 1,240 megawatts, of which Georgia Power’s portion is 1,040 megawatts and Savannah Electric’s portion is 200 megawatts. This new generation became available in June 2005. See Note 3 to the financial statements of Georgia Power and Savannah Electric under “Retail Regulatory Matters — Plant McIntosh Construction Project” in Item 8 herein for additional information.

     Georgia Power and Savannah Electric received Georgia PSC approval of the 2004 IRP in July 2004. Through the approval of the 2004 IRP, Georgia Power de-certified the Atkinson combustion turbine units 5A and 5B totaling approximately 80 megawatts of capacity and Savannah Electric extended the life of the Kraft combustion turbine unit until such time as its retirement is warranted. Georgia Power and Savannah Electric issued an RFP in July 2005 for approximately 1,000 megawatts to meet their future supply-side capacity needs for 2009 and beyond. With the planned merger of Savannah Electric into Georgia Power, this RFP will be consolidated by Georgia Power which will be the sole party to these contracts. In March 2006, Georgia Power is scheduled to issue RFPs for approximately 2,100 and 1,400 megawatts, respectively, to meet its 2010 and 2011 supply-side needs. For the 2011 RFP, Georgia Power will submit a self-build proposal that compares to the market. Additionally, Georgia Power and, until completion of the planned merger, Savannah Electric will each continue a residential load management program which was certified by the Georgia PSC for up to 40 megawatts of equivalent supply-side capacity. Georgia Power will continue to utilize approximately eight megawatts of capacity from existing qualifying facilities under firm contracts and continue to add additional resources as ordered by the Georgia PSC.

     In January 2006, Georgia Power filed an application with the Georgia PSC to approve an amendment to Georgia Power’s IRP in connection with the merger to add Savannah Electric customers and generating assets.

Environmental Cost Recovery Plans

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

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     The Florida Legislature has adopted legislation for an Environmental Cost Recovery Clause, which allows Gulf Power to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation and a return on invested capital. This legislation was amended in 2002 to allow recovery of costs incurred as a result of an agreement between Gulf Power and the Florida Department of Environmental Protection for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters” in Item 8 herein for additional information.

     In 1992, the Mississippi PSC approved Mississippi Power’s Environmental Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to facilitate the Mississippi PSC’s overview of Mississippi Power’s environmental strategy and provides for recovery of costs (including costs of capital associated with environmental projects approved by the Mississippi PSC). Under the ECO Plan, any increase in the annual revenue requirement is limited to two percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the two percent limit into the next year’s revenue requirement. Mississippi Power conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. Mississippi Power recovers such costs under the ECO Plan as they are incurred, as provided for in Mississippi Power’s 1994 ECO Plan order. Mississippi Power filed its 2006 ECO Plan in February 2006, which, if approved as filed, will result in a decrease in customer prices. See Note 3 to the financial statements of Mississippi Power under “Environmental Compliance Overview Plan” in Item 8 herein for additional information.

Storm Damage Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters - Storm Damage Recovery” of Southern Company, Gulf Power and Mississippi Power and “PSC Matters — Natural Disaster Cost Recovery” of Alabama Power in Item 7 herein and to Note 3 to the financial statements of Southern Company, Alabama Power, Gulf Power and Mississippi Power under “Storm Damage Cost Recovery,” “Retail Regulatory Matters — Natural Disaster Cost Recovery,” “Retail Regulatory Matters — Storm Damage Cost Recovery” and “Retail Regulatory Matters — Storm Damage Cost Recovery,” respectively, in Item 8 herein for a discussion of the impacts and recovery of storm damage costs related to Hurricanes Ivan, Dennis and Katrina.

Employee Relations

The Southern Company system had a total of 25,554 employees on its payroll at December 31, 2005.

	Employees
	at
	December 31, 2005
Alabama Power		6,621
Georgia Power		8,713
Gulf Power		1,335
Mississippi Power		1,254
Savannah Electric		560
SCS		3,415
Southern Company Gas		*
Southern Holdings**		11
Southern Nuclear		3,101
Southern Power		***
Other		544
Total		25,554

*	Southern Company Gas has no employees. Southern Company Gas has agreements with SCS and Georgia Power whereby employee services are rendered at cost.
**	One of Southern Holdings’ subsidiaries has 11 employees. Southern Holdings has agreements with SCS whereby all other employee services are rendered at cost.
***	Southern Power has no employees. Southern Power has agreements with SCS and the retail operating companies whereby employee services are rendered at cost.

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

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

     Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2008.

     Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through October 14, 2009.

     Mississippi Power has an agreement with the IBEW on a four-year contract extending to August 16, 2006. Negotiations on a new agreement are expected to begin in July 2006.

     Savannah Electric has agreements with the IBEW and the Office and Professional Employees International Union that expire April 15, 2006 and December 1, 2006, respectively. The status of these agreements is expected to be negotiated and resolved prior to the completion of the merger of Savannah Electric with and into Georgia Power by July 2006.

     Southern Nuclear has agreements with the IBEW on a three-year contract extending to June 30, 2008 for Plants Hatch and Vogtle and a five-year contract which expires August 15, 2006 for Plant Farley. Negotiations on the Plant Farley contract are expected to begin in June 2006. Upon notice given at least 60 days prior to these dates, negotiations may be initiated with respect to agreement terms to be effective after such dates.

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

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Item 1A. RISK FACTORS

In addition to the other information in this Form 10-K, including MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.

Risks Related to the Energy Industry

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

     Southern Company and its subsidiaries, including the retail operating companies and Southern Power, are subject to substantial regulation from federal, state and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of their businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of fossil-fuel, hydroelectric and nuclear generating facilities. For example, the rates charged to wholesale customers by the retail operating companies and by Southern Power must be approved by the FERC. In addition, the respective state PSCs must approve the retail operating companies’ rates for retail customers. While the retail rates approved by the respective state PSCs are designed to provide for recovery of costs and a return on invested capital, there can be no assurance that a state PSC will not deem certain costs to be imprudently incurred and not subject to recovery.

     Until February 8, 2006, Southern Company was subject to regulation by the SEC under the Holding Company Act. In July 2005, the U.S. Congress passed the Energy Act of 2005 which, among other things, repealed the Holding Company Act effective February 8, 2006. Under the Energy Act of 2005, the FERC was provided with new oversight responsibilities for the electric utility industry.

     Southern Company and its subsidiaries believe the necessary permits, approvals and certificates have been obtained for its existing operations and that their respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries cannot now be predicted. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs.

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

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

     The retail operating companies currently own and operate transmission facilities as part of a vertically integrated utility. Transmission revenues are not separated from generation and distribution revenues in their approved retail rates. Since 1999, when the FERC issued final rules on RTOs, there have been a number of proceedings at FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. Under this new transmission regulatory structure, the retail operating companies could transfer functional control (but not ownership) of their transmission facilities to an independent third party. While there are no active proceedings at FERC that would require Southern Company to participate in a RTO, current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. The financial condition, net income and cash flows of Southern Company and its utility subsidiaries

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could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

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

     As a result of the energy crisis in California during the summer of 2001, the Enron Corporation bankruptcy, investigations by governmental authorities into energy trading activities and the August 2003 power outage in the Northeast, companies in regulated and unregulated electric utility businesses have been under an increased amount of public and regulatory scrutiny with respect to, among other things, accounting practices, financial disclosures and relationships with independent auditors. This increased scrutiny has led to substantial changes in laws and regulations affecting Southern Company and its subsidiaries, including, among others, enhanced internal control and auditor independence requirements, financial statement certification requirements, more frequent SEC reviews of financial statements and accelerated and additional SEC filing requirements. New accounting and disclosure requirements have changed the way Southern Company and its subsidiaries are required to record revenues, expenses, assets and liabilities. Southern Company expects continued regulatory focus on accounting and financial reporting issues. Future disruptions in the industry such as those described above and any additional resulting regulations may have a negative impact on the net income or access to capital of Southern Company and its subsidiaries.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs which could negatively impact the net income of Southern Company and the retail operating companies and the value of their respective assets.

     Increased competition, which may result from restructuring efforts, could have a significant adverse financial impact on Southern Company and its retail operating companies. Increased competition could result in increased pressure to lower the cost of electricity. Any adoption in the territories served by the retail operating companies of retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on Southern Company and the retail operating companies due to an impairment of assets, a loss of retail customers, lower profit margins, an inability to recover reasonable costs or increased costs of capital. Southern Company and the retail operating companies cannot predict if or when they may be subject to changes in legislation or regulation, nor can Southern Company and the retail operating companies predict the impact of these changes.

     Additionally, the electric utility industry has experienced a substantial increase in competition at the wholesale level. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. In addition, FERC rules on transmission service are designed to facilitate competition in the wholesale market on a nationwide basis, by providing greater flexibility and more choices to wholesale power customers.

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

     Each of the retail operating companies and Southern Power have authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event

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that FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than market-based rates.

     In addition, in May 2005 the FERC started an investigation to determine whether Southern Company satisfies the other three parts of FERC’s market-based rate analysis: transmission market power, barriers to entry and affiliate abuse or reciprocal dealing. Any and all new market-based rate transactions involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the refund period beginning July 19, 2005.

     In May 2005, the FERC also initiated a proceeding to examine the provisions of the IIC, whether any parties to the IIC have violated FERC’s standards of conduct applicable to utility companies that are transmission providers, and whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent FERC orders any changes to the IIC.

Risks Related to Environmental Regulation

Southern Company’s and the retail operating companies’ costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws and the incurrence of environmental liabilities could harm the net income and cash flows of Southern Company, the retail operating companies or Southern Power.

     Southern Company and the retail operating companies are subject to extensive federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires Southern Company and the retail operating companies to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of their respective facilities. These expenditures are significant and Southern Company and the retail operating companies expect that they will increase in the future. Through 2005, Southern Company had spent approximately $1.6 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂ and NO_x emissions, to maintain compliance with existing regulations and to meet new requirements.

     Approximately $1.3 billion of these expenditures related to reducing NO_x emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NO_x reduction rules.

     Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent.

     If Southern Company, the retail operating companies or Southern Power fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in the assessment of civil or criminal penalties and fines. The EPA has filed civil actions against Alabama Power, Georgia Power and Savannah Electric alleging violations of the new source review provisions of the Clean Air Act. Georgia Power is a party to a civil suit regarding alleged violations of the Clean Air Act at four units of Plant Wansley, and Southern Company is a party to a suit alleging its emissions of carbon dioxide, a greenhouse gas, contribute to global warming. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

     Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be

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

Risks Related to Southern Company and its Business

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

     Southern Company is a holding company and, as such, Southern Company has no operations of its own. Southern Company’s ability to meet its financial obligations and to pay dividends on its common stock at the current rate is primarily dependent on the net income and cash flows of its subsidiaries and their ability to pay upstream dividends or to repay funds to Southern Company. Prior to funding Southern Company, Southern Company’s subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends.

The financial performance of Southern Company and its subsidiaries may be adversely affected if its subsidiaries are unable to successfully operate their facilities.

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

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

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

• labor disputes;

• terrorist attacks;

• fuel or material supply interruptions; and

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

     A decrease or elimination of revenues from power produced by the electric generating facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected retail operating company or Southern Power and of Southern Company.

     In addition, Southern Company’s non-utility businesses depend on the successful operation of their respective facilities. For example, the net income and cash flows of SouthernLINC Wireless and Southern Company could be adversely impacted in the event of a major failure of its telecommunications facilities.

The revenues of Southern Company, the retail operating companies and Southern Power depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, or the failure to renew the PPAs, could have a negative impact on the net income and cash flows of the affected retail operating company or Southern Power and of Southern Company.

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

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Southern Company, the retail operating companies and Southern Power may incur additional costs or delays in power plant construction and may not be able to recover their investment. The facilities of Southern Company, the retail operating companies and Southern Power require ongoing capital expenditures.

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

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

• work stoppages;

• permits, approvals and other regulatory matters;

• adverse weather conditions;

• unforeseen engineering problems;

• environmental and geological conditions;

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

• unanticipated cost increases; and

• attention to other projects.

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

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

Changes in technology may make Southern Company’s electric generating facilities owned by the retail operating companies and Southern Power less competitive.

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

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

     Alabama Power owns two nuclear units and Georgia Power holds undivided interests in, and contracts for operation of, four nuclear units. These six units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 9.1% of Southern Company’s generation capacity as of December 31, 2005. These nuclear facilities are subject to environmental, health and financial risks such as on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities and the threat of a possible terrorist attack. Alabama Power and Georgia Power

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maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of insurance coverage.

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

     In addition, potential terrorist threats and increased public scrutiny of utilities could result in increased nuclear licensing or compliance costs that are difficult or impossible to predict.

The generation and energy marketing operations of Southern Company, the retail operating companies and Southern Power are subject to risks, many of which are beyond their control, including changes in power prices and fuel costs, that may reduce Southern Company’s, the retail operating companies’ and Southern Power’s revenues and increase costs.

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

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

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

• liquidity in the general wholesale electricity market;

• weather conditions impacting demand for electricity;

• seasonality;

• transmission or transportation constraints or inefficiencies;

• availability of competitively priced alternative energy sources;

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

• the financial condition of market participants;

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

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

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

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

     As a result of increasing fuel costs, the retail operating companies have accrued significant underrecovered fuel cost balances. In addition, Alabama Power, Gulf Power and Mississippi Power have significant deficit balances in their storm cost recovery reserves as a result of Hurricanes Ivan, Dennis and Katrina. While the retail operating companies are generally authorized under state legislation administered by the

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respective PSCs to recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs through special rate provisions, recovery may be denied if costs are deemed to be imprudently incurred and delays in the authorization of such recovery could negatively impact the cash flows of the affected retail operating companies and Southern Company.

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

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

The retail operating companies and Southern Power may not be able to obtain adequate fuel supplies, which could limit their ability to operate their facilities.

     The retail operating companies and Southern Power purchase fuel, including coal, natural gas and fuel oil, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, weather, labor relations, force majuere events or environmental regulations affecting any of these fuel suppliers, could limit the ability of the retail operating companies and Southern Power to operate their respective facilities, and thus, reduce the net income of the affected retail operating company or Southern Power and Southern Company.

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

     In addition, Southern Power in particular, and the retail operating companies to a lesser extent, are dependent on natural gas for a portion of their electric generating capacity. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed. For example, in connection with the 2005 hurricanes in the Gulf of Mexico, production and distribution of natural gas was limited for a period of time, resulting in shortages and significant increases in the price of natural gas. In addition, world market conditions for fuels, including the policies of the Organization of Petroleum Exporting Companies, can impact the price and availability of natural gas.

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

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

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Power would not have the ability to recover any of these costs. These situations could have negative impacts on net income and cash flows for the affected retail operating company or Southern Power and Southern Company.

The operating results of Southern Company, the retail operating companies and Southern Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.

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

Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation have filed a claim against Southern Company seeking substantial monetary damages in connection with transfers made by Mirant to Southern Company prior to the Mirant spin-off.

     In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code, and in January 2006, completed its plan of reorganization.

     In 2005, Mirant, as debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company in 1999 and 2000 with actual intent to hinder, delay or defraud creditors, or, alternatively, when Southern Company knew or should have known that Mirant was allegedly insolvent, undercapitalized or unable to pay its debts. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees and costs. In addition, Mirant has objected to Southern Company’s claims against Mirant in the Bankruptcy Court and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. While Southern Company believes there is no meritorious basis for Mirant’s claims and intends to vigorously defend itself in the action, the ultimate outcome of Mirant’s claims cannot be determined at this time.

IRS challenges to Southern Company’s income tax deductions taken in connection with four international leveraged lease transactions could result in the payment of substantial additional interest and penalties and could materially impact Southern Company’s cash flow and net income.

     Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. In connection with its audit of Southern Company’s tax returns for 1996 through 2001, the IRS proposed to disallow Southern Company’s tax losses related to one international leveraged lease (a lease-in-lease-out, or LILO) transaction. In February 2005, Southern Company reached a negotiated settlement with the IRS relating to this matter, which is subject to final approval.

     In addition, the IRS has challenged Southern Company’s deductions related to the three other international leases (sale-in-lease-out, or SILO) transactions in connection with its audit of Southern Company’s 2000 and 2001 tax returns. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company could be subject to additional interest charges of up to $34 million, and the IRS has proposed a penalty of approximately $16 million. Although the payment of the tax liability, exclusive of this interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Furthermore, the Financial Accounting Standards Board has recently proposed changes to the accounting for both leveraged leases and uncertain tax positions that are expected to become effective in 2006. For the LILO transaction, Southern

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Company’s estimates the cumulative effect upon adoption of the accounting change would reduce Southern Company’s net income by approximately $16 million. The impact of these proposed changes related to the SILO transactions would be dependent on the outcome of ongoing negotiations with the IRS, but could be significant, and potentially material, to Southern Company’s net income.

Risks Related to Market and Economic Volatility

The business of Southern Company, the retail operating companies and Southern Power is dependent on their ability to successfully access capital markets. The inability of Southern Company, any retail operating company or Southern Power to access capital may limit its ability to execute its business plan or pursue improvements and make acquisitions that Southern Company, the retail operating companies or Southern Power may otherwise rely on for future growth.

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

• an economic downturn;

• the bankruptcy of an unrelated energy company;

• capital market conditions generally;

• market prices for electricity and gas;

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

• war or threat of war; or

• the overall health of the utility industry.

Southern Company, the retail operating companies and Southern Power are subject to risks associated with a changing economic environment, including their ability to obtain insurance, the financial stability of their respective customers and their ability to raise capital.

     The September 11, 2001 terrorist attacks, the continuing threat of terrorism and the related military action by the United States have affected the nation’s economy and financial markets. The insurance industry has also been disrupted by these events. The availability of insurance covering risks Southern Company, the retail operating companies, Southern Power and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the retail operating companies and Southern Power are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. Any economic downturn or disruption of financial markets could constrain the capital available to Southern Company’s, the retail operating companies’ and Southern Power’s industry and could reduce access to funding for the respective operations of Southern Company, the retail operating companies and Southern Power, as well as the financial stability of their respective customers and counterparties. These factors could adversely affect Southern Company’s subsidiaries’ ability to achieve energy sales growth, thereby decreasing Southern Company’s level of future net income.

Certain of the retail operating companies have substantial investments in the Gulf Coast region which can be subject to major storm activity. The ability of the retail operating companies to recover costs and replenish reserves in the event of a major storm, other natural disaster, terrorist attack or other catastrophic event generally will require regulatory action.

     Each retail operating company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. In September 2004, Hurricane Ivan hit the Gulf coast of Florida and Alabama, causing significant damage to the service areas of Alabama Power and Gulf Power. In July and August

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2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf coast of the United States and caused significant damage in the service areas of Gulf Power, Alabama Power and Mississippi Power. In each case, costs to the respective retail operating companies exceeded their respective storm cost reserves and insurance coverage. In the event a retail operating company experiences a natural disaster, terrorist attack or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of the respective state PSC. While the retail operating companies generally are entitled to recover prudently incurred costs incurred in connection with such an event, any denial by the state PSC or delay in recovery of any portion of such costs could have a material negative impact on a retail operating company’s result of operations and/or cash flows.

Increases in the price of oil may limit tax credits available to Southern Company under Section 29 of the Internal Revenue Code in connection synthetic fuel investments and could result in impairments to Southern Company’s investments in synthetic fuel projects.

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

Item 1B. UNRESOLVED STAFF COMMENTS.

None.

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Item 2. PROPERTIES

Electric Properties – The Electric Utilities

The retail operating companies, Southern Power and SEGCO, at December 31, 2005, owned and/or operated 34 hydroelectric generating stations, 31 fossil fuel generating stations, three nuclear generating stations and 11 combined cycle/cogeneration stations. The amounts of capacity for each company are shown in the table below.

		Nameplate
Generating Station	Location	Capacity(1)
		(Kilowatts)
FOSSIL STEAM
Gadsden	Gadsden, AL		120,000
Gorgas	Jasper, AL		1,221,250
Barry	Mobile, AL		1,525,000
Greene County	Demopolis, AL		300,000	(2)
Gaston Unit 5	Wilsonville, AL		880,000
Miller	Birmingham, AL		2,532,288	(3)
Alabama Power Total			6,578,538
Bowen	Cartersville, GA		3,160,000
Branch	Milledgeville, GA		1,539,700
Hammond	Rome, GA		800,000
McDonough	Atlanta, GA		490,000
McManus	Brunswick, GA		115,000
Mitchell	Albany, GA		125,000
Scherer	Macon, GA		750,924	(4)
Wansley	Carrollton, GA		925,550	(5)
Yates	Newnan, GA		1,250,000
Georgia Power Total			9,156,174
Crist	Pensacola, FL		1,022,500
Lansing Smith	Panama City, FL		305,000
Scholz	Chattahoochee, FL		80,000
Daniel	Pascagoula, MS		500,000	(6)
Scherer Unit 3	Macon, GA		204,500	(4)
Gulf Power Total			2,112,000
Eaton	Hattiesburg, MS		67,500
Sweatt	Meridian, MS		80,000
Watson	Gulfport, MS		1,012,000
Daniel	Pascagoula, MS		500,000	(6)
Greene County	Demopolis, AL		200,000	(2)
Mississippi Power Total			1,859,500
McIntosh	Effingham County, GA		163,117
Kraft	Port Wentworth, GA		281,136
Savannah Electric Total			444,253
Gaston Units 1-4	Wilsonville, AL
SEGCO Total			1,000,000	(7)
Total Fossil Steam			21,150,465
NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total			1,720,000
Hatch	Baxley, GA		899,612	(8)
Vogtle	Augusta, GA		1,060,240	(9)
Georgia Power Total			1,959,852
Total Nuclear Steam			3,679,852
COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total			720,000
Bowen	Cartersville, GA		39,400
Intercession City	Intercession City, FL		47,667	(10)
McDonough	Atlanta, GA		78,800
McIntosh Units 1,2,3,4,7,8	Effingham County, GA		480,000
McManus	Brunswick, GA		481,700
Mitchell	Albany, GA		118,200
Robins	Warner Robins, GA		158,400
Wansley	Carrollton, GA		26,322
Wilson	Augusta, GA		354,100
Georgia Power Total			1,784,589
Lansing Smith Unit A	Panama City, FL		39,400
Pea Ridge Units 1-3	Pea Ridge, FL		15,000
Gulf Power Total			54,400
Chevron Cogenerating Station	Pascagoula, MS		147,292	(11)
Sweatt	Meridian, MS		39,400
Watson	Gulfport, MS		39,360
Mississippi Power Total			226,052
Boulevard	Savannah, GA		59,100
Kraft	Port Wentworth, GA		22,000
McIntosh Units 5&6	Effingham County, GA		160,000
Savannah Electric Total			241,100

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		Nameplate
Generating Station	Location	Capacity
		(Kilowatts)
Dahlberg	Jackson County, GA		756,000
Oleander	Cocoa, FL		628,400
Southern Power Total			1,384,400
Gaston(SEGCO)	Wilsonville, AL		19,680	(7)
Total Combustion Turbines			4,430,221
COGENERATION
Washington County	Washington County, AL		123,428
GE Plastics Project	Burkeville, AL		104,800
Theodore	Theodore, AL		236,418
Alabama Power Total			464,646
COMBINED CYCLE
Barry	Mobile, AL
Alabama Power Total			1,070,424
McIntosh Units 10&11	Effingham County, GA
Georgia Power Total			1,106,178	(13)
Smith	Lynn Haven, FL
Gulf Power Total			545,500
Daniel (Leased)	Pascagoula, MS
Mississippi Power Total			1,070,424
McIntosh Units 10&11	Effingham County, GA
Savannah Electric Total			212,742	(13)
Stanton Unit A	Orlando, FL		428,649	(14)
Harris	Autaugaville, AL		1,318,920
Franklin	Smiths, AL		1,198,360
Wansley	Carrollton, GA		1,073,000
Southern Power Total			4,018,929
Total Combined Cycle			8,024,197
HYDROELECTRIC FACILITIES
Bankhead	Holt, AL		53,985
Bouldin	Wetumpka, AL		225,000
Harris	Wedowee, AL		132,000
Henry	Ohatchee, AL		72,900
Holt	Holt, AL		48,000
Jordan	Wetumpka, AL		100,000
Lay	Clanton, AL		177,000
Lewis Smith	Jasper, AL		157,500
Logan Martin	Vincent, AL		135,000
Martin	Dadeville, AL		182,000
Mitchell	Verbena, AL		170,000
Thurlow	Tallassee, AL		81,000
Weiss	Leesburg, AL		87,750
Yates	Tallassee, AL		47,000
Alabama Power Total			1,669,135
Barnett Shoals (Leased)	Athens, GA		2,800
Bartletts Ferry	Columbus, GA		173,000
Goat Rock	Columbus, GA		38,600
Lloyd Shoals	Jackson, GA		14,400
Morgan Falls	Atlanta, GA		16,800
North Highlands	Columbus, GA		29,600
Oliver Dam	Columbus, GA		60,000
Rocky Mountain	Rome, GA		215,256	(12)
Sinclair Dam	Milledgeville, GA		45,000
Tallulah Falls	Clayton, GA		72,000
Terrora	Clayton, GA		16,000
Tugalo	Clayton, GA		45,000
Wallace Dam	Eatonton, GA		321,300
Yonah	Toccoa, GA		22,500
6 Other Plants			18,080
Georgia Power Total			1,090,336
Total Hydroelectric Facilities			2,759,471
Total Generating Capacity			40,508,852

Notes:
(1)	See “Jointly-Owned Facilities” herein for additional information.
(2)	Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively.
(3)	Capacity shown is Alabama Power’s portion (91.84%) of total plant capacity.
(4)	Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3.
(5)	Capacity shown is Georgia Power’s portion (53.5%) of total plant capacity.
(6)	Represents 50% of the plant which is owned as tenants in common by Gulf Power and Mississippi Power.

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(7)	SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.
(8)	Capacity shown is Georgia Power’s portion (50.1%) of total plant capacity.
(9)	Capacity shown is Georgia Power’s portion (45.7%) of total plant capacity.
(10)	Capacity shown represents 33-1/3% of total plant capacity. Georgia Power owns a 1/3 interest in the unit with 100% use of the unit from June through September. Progress Energy operates the unit.
(11)	Generation is dedicated to a single industrial customer.
(12)	Capacity shown is Georgia Power’s portion (25.4%) of total plant capacity. OPC operates the plant.
(13)	Capacity shown is Georgia Power’s portion (83.87%) and Savannah Electric’s portion (16.13%), respectively, of total plant capacity.
(14)	Capacity shown is Southern Power’s portion (65%) of total plant capacity.

     Except as discussed below under “Titles to Property,” the principal plants and other important units of the retail operating companies, Southern Power and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.

     Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2005, the unamortized portion of this cost was approximately $27.7 million.

     The all-time maximum demand on the retail operating companies, Southern Power and SEGCO was 35,049,600 kilowatts and occurred on July 26, 2005. This amount excludes demand served by capacity retained by MEAG, OPC and SEPA. The reserve margin for the retail operating companies, Southern Power and SEGCO at that time was 14.4%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands.

Jointly-Owned Facilities

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

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

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

     In addition, Georgia Power has commitments regarding a portion of a five percent interest in Plant Vogtle owned by MEAG that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG’s bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit’s variable

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operating costs. Except for the portion of the capacity payments related to the Georgia PSC’s disallowances of Plant Vogtle costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power’s Statements of Income in Item 8 herein.

Titles to Property

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

Item 3. LEGAL PROCEEDINGS

(1)	United States of America v. Alabama Power (United States District Court for the Northern District of Alabama)
	United States of America v. Georgia Power and Savannah Electric (United States District Court for the Northern District of Georgia) See “Environmental Matters — New Source Review Actions” in Note 3 to Southern Company’s and each retail operating company’s financial statements in Item 8 herein for information.
(2)	Environmental Remediation
	See “Environmental Matters — Environmental Remediation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s and Mississippi Power’s financial statements in Item 8 herein for information related to environmental remediation.
(3)	In re: Mirant Corporation, et al. (U.S. Bankruptcy Court for the Northern District of Texas)
	See “Mirant Matters — Mirant Bankruptcy” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
(4)	MC Asset Recovery, LLC v. Southern Company (in process of transfer to the U.S. District Court for the Northern District of Georgia from the U.S. District Court for the Northern District of Texas) (formerly styled In re: Mirant Corporation, et al. in the U.S. Bankruptcy Court for the Northern District of Texas)
	See “Mirant Matters — Mirant Bankruptcy Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.

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

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

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

Southern Company, Alabama Power, Georgia Power, Mississippi Power, Savannah Electric and Southern Power

None.

Gulf Power

On October 27, 2005, in an action taken by written consent, Southern Company as the sole shareholder of Gulf Power at that time, approved a plan of domestication under which Gulf Power, originally formed under the laws of the State of Maine on November 2, 1925, was domesticated as a Florida corporation, effective at 12:01 a.m. Eastern Standard Time on November 2, 2005. Under applicable law, the domestication does not affect the inception date of Gulf Power nor does it affect any obligations or liabilities of Gulf Power incurred prior to its domestication.

     In connection with the domestication, on October 27, 2005, Southern Company as the sole shareholder of Gulf Power at that time, in actions taken by written consent, also approved amended and restated Articles of Incorporation of Gulf Power and adopted amendments to the bylaws of Gulf Power. The amended and restated Articles of Incorporation were filed with the Florida Secretary of State on October 27, 2005 and such Articles and the amended bylaws became effective on November 2, 2005.

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EXECUTIVE OFFICERS OF SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)The ages of the officers set forth below are as of December 31, 2005.

David M. Ratcliffe
Chairman, President, Chief Executive Officer and
Director
Age 57

Elected in 1999. President since April 2004; Chairman and Chief Executive Officer since July 2004. Previously served as Chief Executive Officer of Georgia Power from June 1999 to April 2004; and President of Georgia Power from June 1999 to December 2003.

Andrew J. Dearman, III
Executive Vice President
Age 52

Elected in 2005. Executive Vice President since December 2005. Previously served as Senior Vice President from December 2000 until December 2005.

Dwight H. Evans
Executive Vice President
Age 57

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

Thomas A. Fanning
Executive Vice President, Chief Financial Officer and Treasurer
Age 48

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

Michael D. Garrett
Executive Vice President
Age 56

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

G. Edison Holland, Jr.
Executive Vice President
Age 53

Elected in 2001. Executive Vice President since 2001. Previously served as Director, President and Chief Executive Officer of Savannah Electric from 1997 until 2001.

Anthony R. James
Executive Vice President
Age 55

Elected in 2005. Executive Vice President of Southern Company since December 2005. Previously served as Chairman of Savannah Electric from December 2005 through January 2006; President and Chief Executive Officer of Savannah Electric from April 2001 to December 2005 and Vice President of Savannah Electric from July 2000 until April 2001.

Charles D. McCrary
Executive Vice President
Age 54

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

W. Paul Bowers
Executive Vice President of SCS
Age 49

Elected in 2001. Executive Vice President of SCS since May 2001 and previously served as President and Chief Executive Officer of Southern Power from May 2001 to March 2005. He also previously served as Senior Vice President and Chief Marketing Officer of Southern Company from March 2000 to May 2001.

J. Barnie Beasley
President and Chief Executive Officer of Southern Nuclear
Age 54

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

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     The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 25, 2005) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified, except for Messrs. Dearman and James, whose elections were effective December 12, 2005.

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EXECUTIVE OFFICERS OF ALABAMA POWER

(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)The ages of the officers set forth below are as of December 31, 2005.

Charles D. McCrary
President, Chief Executive Officer and Director
Age 54
Elected in 2001. President, Chief Executive Officer and Director since October 2001; Executive Vice President of Southern Company since February 2002. Previously served as President and Chief Operating Officer of Alabama Power from April 2001 to October 2001; and Vice President of Southern Company from February 1998 to April 2001.

Art P. Beattie
Executive Vice President, Chief Financial Officer and Treasurer
Age 51
Elected in 2004. Executive Vice President, Chief Financial Officer and Treasurer since February 2005. Previously served as Vice President and Comptroller of Alabama Power from 1998 through January 2005.

C. Alan Martin
Executive Vice President
Age 57
Elected in 1999. Executive Vice President of the Customer Service Organization since 2001. Previously served as Executive Vice President of External Affairs from January 2000 to April 2001.

Steven R. Spencer
Executive Vice President
Age 50
Elected in 2001. Executive Vice President of External Affairs since 2001. Previously served as Senior Vice President of External Affairs from July 2000 to April 2001.

Jerry L. Stewart
Senior Vice President
Age 56
Elected in 1999. Senior Vice President of Fossil and Hydro Generation since 1999.

     The officers of Alabama Power were elected for a term running from the last annual organizational meeting of the directors (April 22, 2005) for one year until the next annual meeting or until their successors are elected and have qualified.

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EXECUTIVE OFFICERS OF MISSISSIPPI POWER

(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.)The ages of the officers set forth below are as of December 31, 2005.

Anthony J. Topazi
President, Chief Executive Officer and Director
Age 55
Elected in 2003. President, Chief Executive Officer and Director since January 1, 2004. Previously served as Executive Vice President of Southern Company Generation and Energy Marketing from November 2000 to December 2003; Senior Vice President of Southern Power from November 2002 to December 2003; and Vice President of Southern Power from 2001 until November 2002.

John W. Atherton
Vice President
Age 45
Elected in 2004. Vice President of External Affairs since January 2005. Previously served as the Director of Economic Development from September 2003 to January 2005; Manager, Sales and Marketing Services from April 2002 to August 2003; and Manager, State Legislative Affairs from August 1996 to April 2002.

Kimberly D. Flowers
Vice President
Age 41
Elected in 2005. Vice President and Senior Production Officer since March 2005. Previously served as Plant Manager, Plant Bowen, Georgia Power from November 2000 until March 2005.

Bobby J. Kerley
Vice President
Age 52
Elected in 2003. Vice President of Customer Services and Retail Marketing since December 2003. Previously served at Alabama Power as Division Vice President — Southeast Division Office from April 2001 to December 2003; Division Manager — Operations, Birmingham Division Office from January 2001 to April 2001; and Transmission Lines Manager, Corporate Headquarters from March 1997 to January 2001.

Frances Turnage
Vice President, Treasurer and
Chief Financial Officer
Age 57
Elected in 2005. Vice President, Treasurer and Chief Financial Officer since March 2005. Previously served as Comptroller from 1993 to March 2005.

     The officers of Mississippi Power were elected for a term running from the last annual organizational meeting of the directors (April 27, 2005) for one year until the next annual meeting or until their successors are elected and have qualified.

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PART II

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

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

	High		Low
2005
First Quarter	$	34.08	$	31.25
Second Quarter		34.91		31.78
Third Quarter		36.16		33.47
Fourth Quarter		36.07		33.28
2004
First Quarter	$	30.87	$	29.10
Second Quarter		30.59		27.86
Third Quarter		30.65		28.86
Fourth Quarter		33.92		29.95

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

(b)	Number of Southern Company’s common stockholders of record at December 31, 2005: 118,285
	Each of the other registrants have one common stockholder, Southern Company.
(c)	Dividends on each registrant’s common stock are payable at the discretion of their respective board of directors. The dividends on common stock declared by Southern Company and the retail operating companies to their stockholder(s) for the past two years were as follows:

Registrant	Quarter	2005		2004
		(in thousands)
Southern Company	First	$	265,958	$	257,506
	Second		277,679		258,318
	Third		277,625		264,051
	Fourth		276,306		264,859
Alabama Power	First	$	102,475	$	109,325
	Second		102,475		109,325
	Third		102,475		109,325
	Fourth		102,475		109,325
Georgia Power	First	$	139,025		141,375
	Second		139,025		141,375
	Third		139,025		141,375
	Fourth		139,025		141,375
Gulf Power	First	$	17,100	$	17,500
	Second		17,100		17,500
	Third		17,100		17,500
	Fourth		17,100		17,500
Mississippi Power	First	$	15,500	$	16,550
	Second		15,500		16,550
	Third		15,500		16,550
	Fourth		15,500		16,550
Savannah Electric	First	$	6,675	$	5,800
	Second		6,675		5,800
	Third		6,675		5,800
	Fourth		6,675		5,800

In 2004 and 2005, Southern Power paid $320 million and $72.4 million, respectively, in dividends to Southern Company.

The dividend paid per share of Southern Company’s common stock was 35¢ for the first two quarters of 2004 and 35.75¢ for the last two quarters of 2004 and first quarter of 2005 and 37.25¢ for the second, third and fourth quarters of 2005.

II-1

At December 31, 2005, in accordance with its first mortgage bond indenture, $68 million of Savannah Electric’s retained earnings was restricted against payment of cash dividends. Southern Power’s credit facility contains potential limitations on the payment of common stock dividends. At December 31, 2005, Southern Power was in compliance with the conditions of this credit facility and thus had no restrictions on its ability to pay common stock dividends. See Note 8 to the financial statements of Southern Company under “Common Stock Dividend Restrictions,” Note 6 to the financial statements of Savannah Electric under “Common Stock Dividend Restrictions” and Note 5 to the financial statements of Southern Power under “Dividend Restriction” in Item 8 herein for additional information regarding these restrictions.

(d) Issuer Purchases of Equity Securities

							Maximum
					Total		Approximate
					Number		Dollar
					Of Shares		Value
					Purchased		Of Shares
					As Part		That
	Total		Average		Of		May Yet
	Number		Price		Publicly		Be Purchased
	Of		Paid		Announced		Under the
	Shares		Per		Plans or		Plans or
2005	Purchased		Share		Programs		Programs (1)
October 1-31		191,417	$	34.19		191,417		N/A
November 1-30		40,241	$	34.46		40,241		N/A
December 1-31		94,333	$	35.04		94,333		N/A
Total		325,991	$	34.47		325,991		N/A

(1) As announced in 2004, in May 2005, Southern Company engaged an agent to (i) begin repurchasing shares of Southern Company common stock to offset the 6,273,876 shares of common stock issued from January 2005 through May 2005 in connection with the exercise of stock options under the Omnibus Plan and (ii) repurchase shares of Southern Company common stock on an ongoing basis to offset additional shares issued in connection with the exercise of stock options under the Omnibus Plan. As of December 31, 2005, Southern Company has repurchased a total of 10,066,958 shares. The repurchase program was discontinued in early January 2006.

Item 6. SELECTED FINANCIAL DATA

     Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-77 and II-78.

     Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-128 and II-129.

     Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-185 and II-186.

     Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-233 and II-234.

     Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-284 and II-285.

     Savannah Electric. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-331 and II-332.

     Southern Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at page II-362.

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

     Southern Company. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-11 through II-37.

     Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-81 through II-99.

     Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-132 through II-151.

     Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-189 through II-207.

     Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-237 through II-256.

II-2

     Savannah Electric. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-288 through II-305.

     Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-335 through II-347.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

II-3

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2005 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, 2005, 2004, and 2003	II-38
Consolidated Balance Sheets at December 31, 2005 and 2004	II-39
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-41
Consolidated Statements of Capitalization at December 31, 2005 and 2004	II-42
Consolidated Statements of Common Stockholders’ Equity for the Years Ended December 31, 2005, 2004, and 2003	II-44
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-44
Notes to Financial Statements	II-45
Alabama Power:
Report of Independent Registered Public Accounting Firm	II-80
Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-100
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-101
Balance Sheets at December 31, 2005 and 2004	II-102
Statements of Capitalization at December 31, 2005 and 2004	II-104
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-106
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-106
Notes to Financial Statements	II-107
Georgia Power:
Report of Independent Registered Public Accounting Firm	II-131
Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-152
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-153
Balance Sheets at December 31, 2005 and 2004	II-154
Statements of Capitalization at December 31, 2005 and 2004	II-156
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-157
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-157
Notes to Financial Statements	II-158
Gulf Power:
Report of Independent Registered Public Accounting Firm	II-188
Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-208
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-209
Balance Sheets at December 31, 2005 and 2004	II-210
Statements of Capitalization at December 31, 2005 and 2004	II-212
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-213

II-4

	Page
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-213
Notes to Financial Statements	II-214
Mississippi Power:
Report of Independent Registered Public Accounting Firm	II-236
Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-257
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-258
Balance Sheets at December 31, 2005 and 2004	II-259
Statements of Capitalization at December 31, 2005 and 2004	II-261
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-262
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-262
Notes to Financial Statements	II-263
Savannah Electric:
Report of Independent Registered Public Accounting Firm	II-287
Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-306
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-307
Balance Sheets at December 31, 2005 and 2004	II-308
Statements of Capitalization at December 31, 2005 and 2004	II-310
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-311
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-311
Notes to Financial Statements	II-312
Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-334
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004, and 2003	II-348
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	II-349
Consolidated Balance Sheets at December 31, 2005 and 2004	II-350
Consolidated Statements of Common Stockholder’s Equity for the Years Ended December 31, 2005, 2004, and 2003	II-352
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004, and 2003	II-352
Notes to Financial Statements	II-353

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

     None.

II-5

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls And Procedures.

     As of the end of the period covered by this annual report, Southern Company, the retail operating companies and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.

Internal Control Over Financial Reporting.

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

(1) Southern Company

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

(2) Retail operating companies and Southern Power

          Not applicable because these companies are not accelerated filers.

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

(1) Southern Company

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

(2) Retail operating companies and Southern Power

          Not applicable because these companies are not accelerated filers.

(c) Changes in internal controls.

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

          There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the fourth quarter 2005 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

Savannah Electric

          During the fourth quarter 2005, Savannah Electric transferred responsibility for certain internal control procedures related to accounting for property, joint ownership, fuel and purchased power transactions to Georgia Power. Savannah Electric continues to review such accounting transactions and maintains overall financial reporting responsibility; however, the transfer of these control procedures constitutes a change in Savannah Electric’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that has materially affected or is reasonably likely to materially affect Savannah Electric’s internal control over financial reporting.

Item 9B. OTHER INFORMATION

     None.

II-6

THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

FINANCIAL SECTION

II-7

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2005 Annual Report

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

     Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2005.

     Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on management’s assessment of the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2005. Deloitte & Touche LLP’s report, which expresses unqualified opinions on management’s assessment and on the effectiveness of Southern Company’s internal control over financial reporting, is included herein.

/s/ David M. Ratcliffe

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

/s/ Thomas A. Fanning

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

February 27, 2006

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, 2005, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

     In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated February 27, 2006 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

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, 2005 and 2004, and the related consolidated statements of income, comprehensive income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

II-10

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2005 Annual Report

OVERVIEW

Business Activities

The primary business of Southern Company (the Company) is electricity sales in the Southeast by the retail operating companies – Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric – and Southern Power. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market.

     Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. These factors include the retail operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration following multiple hurricanes. Since the beginning of 2004, each of the retail operating companies completed successful retail rate proceedings. These regulatory actions are expected to benefit future earnings stability and enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and to continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future. In addition, Georgia Power, Gulf Power, and Mississippi Power expect further rate proceedings in 2006 as necessary to address fuel and storm damage cost recovery.

     Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Southern Power continued executing its regional strategy in 2005 by signing several wholesale contracts with major utilities, as well as with cooperatives and municipal suppliers in the Southeast. However, the Company continues to face regulatory challenges related to transmission and market power issues at the national level.

     Southern Company’s other business activities include investments in synthetic fuel producing entities, which claim federal income tax credits that offset their operating losses, leveraged lease projects, telecommunications, and energy-related services. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly. In January 2006, the sale of the Company’s natural gas marketing business was completed.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective energy to more than 4 million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS). Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects. The 2005 Peak Season EFOR performance was slightly below target (as shown in the chart below) primarily due to an outage event at a combined cycle unit. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2005 performance was above target on these reliability measures. EPS is the measure for Southern Company’s efforts to increase returns to shareholders through average long-term earnings per share growth of 5 percent.

II-11

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

     Southern Company’s 2005 results compared with its targets for some of these key indicators are reflected in the following chart:

Key Performance	2005 Target	2005 Actual
Indicator	Performance	Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season EFOR	2.75% or less	2.83%
EPS	$2.04 - $2.09	$2.14

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.

Earnings

Southern Company’s financial performance in 2005 remained strong, despite the challenges of rising costs and major hurricanes. Net income was $1.59 billion in 2005, an increase of 3.8 percent over the prior year. Net income was $1.53 billion in 2004 and $1.47 billion in 2003, reflecting increases over the prior year of 4.0 percent and 11.8 percent, respectively. Basic EPS, including discontinued operations, was $2.14 in 2005, $2.07 in 2004, and $2.03 in 2003. Diluted EPS, which factors in additional shares related to stock options, was 1 cent lower than basic EPS each year.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.475 in 2005, $1.415 in 2004, and $1.385 in 2003. In January 2006, Southern Company declared a quarterly dividend of 37.25 cents per share. This is the 233rd consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company’s goal for the dividend payout ratio is to achieve and maintain a payout of approximately 70 percent of net income, excluding earnings from synthetic fuel businesses. For 2005, the actual payout ratio was 73 percent excluding synthetic fuel earnings, and 69 percent overall.

RESULTS OF OPERATIONS

Electricity Businesses

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

			Increase (Decrease)
	Amount		from Prior Year
	2005		2005		2004			2003
	(in millions)
Electric operating revenues	$	13,278	$	1,813	$	718		$	541
Fuel		4,488		1,089		400			213
Purchased power		731		88		170			24
Other operation and maintenance		3,220		215		148			105
Depreciation and amortization		1,137		229		(64	)		(16	)
Taxes other than income taxes		676		52		40			29
Total electric operating expenses		10,252		1,673		694			355
Operating income		3,026		140		24			186
Other income, net		62		38		22			20
Interest expenses		676		62		19			10
Income taxes		899		24		30			68
Net income	$	1,513	$	92	$	(3	)	$	128

Revenues

Details of electric operating revenues are as follows:

	2005			2004			2003
				(in millions)
Retail — prior year	$	9,732		$	8,875		$	8,728
Change in –
Base rates		236			41			75
Sales growth		184			216			104
Weather		34			48			(135	)
Fuel and other cost recovery clauses		979			552			103
Retail current year		11,165			9,732			8,875
Sales — for resale		1,667			1,341			1,358
Other electric operating revenues		446			392			514
Electric operating revenues	$	13,278		$	11,465		$	10,747
Percent change		15.8	%		6.7	%		5.3	%

     Retail revenues increased $1.4 billion in 2005, $857 million in 2004, and $147 million in 2003. The

II-12

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

significant factors driving these changes are shown in the preceding table. The increase in base rates in 2005 is primarily due to approval by the Georgia Public Service Commission (PSC) of retail base rate increases at Georgia Power and Savannah Electric. Electric rates for the retail operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased energy costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased energy, and do not affect net income. Certain of the retail operating companies also have clauses to recover other costs, such as environmental, storm damage, new plants, and/or purchased power agreements (PPAs).

     Sales for resale revenues increased $326 million in 2005, decreased $17 million in 2004, and increased $190 million in 2003. In 2005, sales for resale revenues increased primarily due to a 26.5 percent increase in the average cost of fuel per net kilowatt-hour (KWH) generated. In addition, Southern Company entered into new PPAs with 30 electric membership cooperatives (EMCs) and Flint EMC, both beginning in January 2005, and in June 2005, in connection with the acquisition of Plant Oleander, assumed two PPAs. In 2004, coal and gas prices increased, resulting in a lower marginal price differential that reduced demand. Mild summer weather throughout the Southeast also reduced demand. In 2003, Southern Company entered into several new PPAs with neighboring utilities. In addition, milder weather in Southern Company’s service territory, compared with the rest of the Southeast and combined with higher gas prices, resulted in increases in both customer demand and available generation.

     Southern Company’s average wholesale contract now extends more than 11 years, and as a result, the Company has significantly limited its remarketing risk. Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect the recovery of fixed costs and a return on investment, and energy is generally sold at variable cost. Unit power energy sales increased 1.7 percent, 1.9 percent, and 4.0 percent in 2005, 2004, and 2003, respectively. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, because the energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The capacity and energy components of the unit power contract revenues were as follows:

	2005		2004		2003
			(in millions)
Unit power –
Capacity	$	201	$	185	$	182
Energy		237		213		211
Total	$	438	$	398	$	393

     Short-term opportunity energy sales are also included in sales for resale. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. Revenues associated with opportunity sales and PPAs were as follows:

	2005		2004		2003
			(in millions)
Other power sales –
Capacity and other	$	430	$	308	$	298
Energy		799		635		667
Total	$	1,229	$	943	$	965

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

Energy Sales

Changes in revenues are influenced heavily by the volume of energy sold each year. KWH sales for 2005 and the percent change by year were as follows:

	Amount		Percent Change
(billions of KWH)	2005		2005			2004			2003
Residential		51.1		2.8	%		3.9	%		(1.9	)%
Commercial		51.9		3.6			3.4			0.3
Industrial		55.1		(2.2	)		3.6			1.0
Other		1.0		(0.9	)		0.8			(0.2	)
Total retail		159.1		1.2			3.6			(0.2	)
Sales for resale		37.8		7.3			(13.0	)		24.5
Total		196.9		2.3			0.1			4.2

     Energy sales in 2005 increased 4.5 billion KWH as a result of sustained economic growth and customer growth of 1.2 percent. Hurricane Katrina dampened customer growth from previous years and was the primary contributor to the decrease in industrial sales in 2005. In addition, in 2005, some Georgia Power industrial customers were reclassified from industrial to commercial to be

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

consistent with the rate structure approved by the Georgia PSC resulting in higher commercial sales and lower industrial sales in 2005 when compared with 2004. Energy sales in 2004 were strong across all retail customer classes as a result of an improved economy in the Southeast and customer growth of 1.5 percent. Residential energy sales in 2003 reflected a decrease in customer demand as a result of very mild weather, partially offset by customer growth of 1.6 percent. In 2003, commercial sales continued to show steady growth while industrial sales increased somewhat over the depressed results of previous years. Energy sales to retail customers are projected to increase at a compound average annual rate of 1.9 percent during the period 2006 through 2011, assuming normal weather conditions.

     Energy sales for resale increased by 2.6 billion KWH in 2005, decreased 5.3 billion KWH in 2004, and increased by 8.0 billion KWH in 2003. The increase in sales in 2005 is related primarily to the new PPAs discussed above. The decrease in 2004 as compared with 2003 is due to the increased availability of coal-fired generation in 2003 resulting from weather-related lower retail demand coupled with higher natural gas prices, which increased the wholesale market demand for opportunity sales.

Fuel and Purchased Power Expenses

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

	2005		2004		2003
Total generation (billions of KWH)		196		188		189
Sources of generation (percent) —
Coal		71		69		71
Nuclear		15		16		16
Gas		11		12		9
Hydro		3		3		4
Average cost of fuel per net KWH generated (cents)		2.39		1.89		1.67
Average cost of purchased power per net KWH (cents)		7.14		4.48		3.86

     In 2005, fuel and purchased power expenses were $5.2 billion, an increase of $1.2 billion or 29.1 percent above the prior year costs. An additional 7.8 billion KWH were generated in 2005 at a 26.5 percent higher average cost per net KWH generated; however, this lowered requirements to purchase even more expensive electricity from non-affiliates.

     Fuel and purchased power expenses were $4.0 billion in 2004, an increase of $570 million or 16.4 percent above 2003 costs. This increase was the result of a 13.2 percent increase in the average cost per net KWH generated and a 16.1 percent increase in the average cost per KWH purchased.

     Fuel and purchased power expenses were $3.5 billion in 2003, an increase of $237 million or 7.3 percent above the prior year costs. This increase was primarily attributed to higher average unit fuel cost and increased customer demand.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China, as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the retail operating companies’ fuel cost recovery provisions. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses were $3.2 billion, $3.0 billion, and $2.9 billion, increasing $215 million, $148 million, and $105 million in 2005, 2004, and 2003, respectively. Other production expenses increased $58 million and $53 million in 2005 and 2004, respectively, and decreased $27 million in 2003. Production expenses fluctuate from year to year due to variations in outage schedules, flexible spending projects, and normal increases in costs.

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

     Administrative and general expenses increased $73 million in 2005 related to a $33 million increase in employee benefits, a $22 million increase in shared services expenses, and a $9 million increase in property insurance. Administrative and general expenses increased $106 million in 2004 primarily related to $41 million, $23 million, and $13 million increases in employee benefits, shared services expenses, primarily nuclear security, and property insurance, respectively. In 2003, administrative and general expenses increased $46 million, due primarily to a $19 million increase in property insurance, a $9 million increase in employee benefits, and $9 million of business development costs at Southern Power.

     Transmission and distribution expenses increased $60 million in 2005, $49 million in 2004, and $23 million in 2003. Transmission and distribution expenses increased in 2005 primarily as a result of $48 million of expenses recorded by Alabama Power in accordance with an accounting order approved by the Alabama PSC primarily to offset the costs of Hurricane Ivan and restore the natural disaster reserve. In accordance with the accounting order, Alabama Power also returned certain regulatory liabilities related to deferred income taxes to its retail customers; therefore, the combined effect of the accounting order had no impact on net income. See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information. Transmission and distribution expenses also fluctuate from year to year due to variations in maintenance schedules, flexible spending projects, and normal increases in costs, and are the primary basis for the 2004 and 2003 increases.

     The 2003 increase in other operation and maintenance expenses also reflects the establishment of a $60 million regulatory liability related to Plant Daniel that was expensed in 2003.

Depreciation and Amortization Expenses

Depreciation and amortization expenses increased $229 million in 2005 as a result of additional plant in service and from the expiration in 2004 of certain provisions in Georgia Power’s retail rate plan for the three years ended December 31, 2004 (2001 Retail Rate Plan). In accordance with the 2001 Retail Rate Plan, Georgia Power amortized an accelerated cost recovery liability as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates over the three years ended December 31, 2004. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.

     Depreciation and amortization expenses declined by $64 million in 2004, primarily as a result of amortization of the Plant Daniel regulatory liability and a Georgia Power regulatory liability related to the levelization of certain purchased power costs that reduced amortization expense by $17 million and $90 million, respectively, from the prior year. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Mississippi Power” herein and Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for more information on these regulatory adjustments. These reductions were partially offset by a higher depreciable plant base.

     The $16 million decrease in depreciation and amortization expenses in 2003 was primarily due to a $49 million reduction in amortization of the previously discussed Georgia Power purchased power regulatory liability and was partially offset by a higher depreciable plant base.

Taxes Other Than Income Taxes

Taxes other than income taxes increased by $52 million in 2005 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales. In 2004, taxes other than income taxes increased $40 million as a result of additional plant in service and a higher property tax base. Taxes other than income taxes increased $29 million in 2003 as a result of additional generating facilities, as well as higher property tax valuations on existing facilities.

Electric Other Income and (Expense)

Total interest charges and other financing costs increased by $62 million in 2005 associated with an additional $863 million in debt outstanding at December 31, 2005 as compared to December 31, 2004 and an increase in average interest rates on variable rate debt. Variable rates on pollution control bonds are highly correlated with the Bond Market Association Municipal Swap Index which averaged 2.5 percent in 2005 and 1.2 percent in 2004. Variable rates on commercial paper and senior notes are highly correlated with the one-month London Interbank Offer Rate (LIBOR), which averaged 3.4 percent in 2005 and 1.5 percent in 2004. An additional $17 million increase in 2005 was the result of a lower percentage of interest costs

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

capitalized as construction projects reached completion. The $19 million increase in interest charges and other financing costs in 2004 was also the result of a lower percentage of interest costs capitalized as construction projects reached completion.

Other Business Activities

Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various energy-related projects, including synthetic fuels and leveraged lease projects that receive tax benefits, which contribute significantly to the economic results of these investments; SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast; Southern Telecom provides fiber optics services in the Southeast; and Southern Company Gas was a retail gas marketer serving customers in the State of Georgia. On January 4, 2006, Southern Company Gas completed the sale of substantially all of its assets and is reflected in the condensed income statement below as discontinued operations. See Note 3 to the financial statements under “Southern Company Gas Sale” for additional information.

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

				Increase (Decrease)
	Amount			from Prior Year
	2005			2005			2004			2003
				(in millions)
Operating revenues	$	276		$	12		$	(7	)	$	30
Operation and maintenance		297			12			28			(23	)
Depreciation and amortization		39			(2	)		(9	)		(7	)
Taxes other than income taxes		4			1			1			—
Total operating expenses		340			11			20			(30	)
Operating income		(64	)		1			(27	)		60
Equity in losses of unconsolidated subsidiaries		(123	)		(26	)		3			(8	)
Leveraged lease income		74			4			4			8
Other income, net		(12	)		(5	)		(15	)		9
Interest expenses		101			18			(21	)		6
Income taxes		(304	)		(14	)		(63	)		23
Discontinued operations, net of tax		—			(3	)		12			(12	)
Net income	$	78		$	(33	)	$	61		$	28

     Southern Company’s non-electric operating revenues increased $12 million in 2005 primarily as the result of higher production and increased fees in the synthetic fuel business. The $7 million decrease in 2004 was primarily due to lower operating revenues in the energy-related services business, partially offset by an increase in SouthernLINC Wireless revenues as a result of increased wireless subscribers. The $30 million increase in revenues in 2003 was primarily due to increased sales in the energy-related services business. Revenues from a subsidiary that primarily provides fuel transportation services related to synthetic fuel products were $123 million in 2005, increasing by $17 million, $21 million, and $37 million in 2005, 2004, and 2003, respectively, as a result of increased production at the synthetic fuel facilities and annual increases in rates. Most of these service revenues are ultimately included in the cost of the synthetic fuel purchased by Alabama Power and Georgia Power and, therefore, have no significant effect on Southern Company’s consolidated revenues. See Note 1 to the financial statements under “Related Party Transactions” for additional information.

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

     Operation and maintenance expenses for these other businesses increased by $12 million in 2005 as a result of $9 million of higher losses for property damage, $2 million in higher network costs at SouthernLINC Wireless, and a $11 million increase in shared services expenses, offset by the 2004 $12.5 million bad debt reserve discussed below. Operation and maintenance expenses increased $28 million in 2004 primarily due to a $3 million increase in advertising, a $5 million increase in shared services expenses, and a $12.5 million bad debt reserve related to additional federal income taxes and interest Southern Company paid on behalf of Mirant Corporation (Mirant). See FUTURE EARNINGS POTENTIAL — “Mirant Bankruptcy Matters” herein and Note 3 to the financial statements under “Mirant Matters — Mirant Bankruptcy” for additional information. Operation and maintenance expenses decreased by $23 million in 2003 primarily due to a $6 million decrease in shared services expenses and a $3 million decrease in losses for property damage at the parent company; a $4 million decrease in bad debt expense and a $3 million decrease in network costs at SouthernLINC Wireless; and a $2 million decrease in salaries in the energy-related services business.

     Depreciation and amortization expenses decreased $9 million and $7 million in 2004 and 2003, respectively. These reductions are primarily the result of $10 million of expenses associated with the repurchase of debt at Southern Holdings recorded in 2003 and a $16 million charge recorded in 2002 related to the impairment of assets under certain customer contracts for energy-related services.

     The increases in equity in losses of unconsolidated subsidiaries in 2005 and 2003 reflect the results of additional production expenses in the synthetic fuel partnerships. These partnerships also claim federal income tax credits that offset their operating losses and make the businesses profitable. These credits totaled $177 million in 2005, $146 million in 2004, and $120 million in 2003. In 2004, a $37 million reserve related to these tax credits was reversed following the settlement of an Internal Revenue Service (IRS) audit. See FUTURE EARNINGS POTENTIAL — “Income Tax Matters” herein for additional information.

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

     Total interest charges and other financing costs increased by $18 million in 2005 associated with an additional $283 million in debt outstanding and a 164 basis point increase in average interest rates on variable rate debt. Interest expense decreased $21 million in 2004 as a result of the parent company’s redemption of preferred securities in 2003. This decrease was partially offset by an increase in outstanding long-term debt in 2004.

Effects of Inflation

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

FUTURE EARNINGS POTENTIAL

General

The retail operating companies operate as vertically integrated companies providing electricity to customers within their service areas in the southeastern United States. Prices for electricity provided to retail customers are set by state PSCs under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Company’s wholesale business continues to focus on long-term capacity contracts, optimized by limited energy trading activities. The level of future earnings depends on numerous factors including the FERC’s market-based rate investigation, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and

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

Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the retail operating companies’ ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area.

     Southern Company system generating capacity increased 1,880 megawatts in 2005 with the completion of Plant McIntosh units 10 and 11 by Georgia Power and Savannah Electric and the acquisition by Southern Power of Plant Oleander. In general, Southern Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities.

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

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions.”

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Plant Wansley Environmental Litigation

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of Georgia Power in part and the plaintiffs in part. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial, which will address civil penalties and possible injunctive relief requested by the plaintiffs.

     The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Environmental Statutes and Regulations

General

Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, Southern Company had invested approximately $2.4 billion in capital projects to comply with these requirements, with annual totals of $423 million, $300 million, and $256 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $7.5 billion, including $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect Southern Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of Southern Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2005, the Company had spent approximately $1.6 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂and NO_xemissions, maintain compliance with existing regulations, and to meet new requirements.

     Approximately $1.3 billion of these expenditures related to reducing NO_x emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NO_x reduction rules. In 2004, the regional NO_x reduction rules were implemented for the northern two-thirds of Alabama. Although the State of Georgia was originally included in the states subject to the regional NO_x rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NO_x reduction rules for the State of Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of its state implementation plan.

     In addition, in 2005, Gulf Power substantially completed the terms of a 2002 agreement with the State of Florida to help ensure attainment of the ozone standard in the Pensacola, Florida area. The conditions of the agreement, which required installing additional controls on certain units and retiring three older units at a plant near Pensacola, will be fully implemented in 2006 at a cost of approximately $134.4 million, of which $4.3 million remains to be spent. Gulf Power’s costs have been approved under its environmental cost recovery clause. See Note 1 to the financial statements under “Environmental Cost Recovery” for additional information.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. Areas within Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham (Alabama), Macon (Georgia), and a 20-county area within metropolitan Atlanta. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, are required for most areas by June 2007. These state implementation plans could require further reductions in NO_x emissions from power plants.

     In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment. The final outcome of this matter cannot now be determined.

     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia, and the EPA proposed

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO₂ and NO_x emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at Southern Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.

     Georgia Power is installing cooling towers at additional facilities under the Clean Water Act to cool water prior to discharge. Near Atlanta, a cooling tower for one plant was completed in 2004 and two others are scheduled for completion in 2008. The total estimated cost of these projects is $173 million, with $85 million remaining to be spent.

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Southern Company and Subsidiary Companies 2005 Annual Report

Georgia Power is also conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.

     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

Environmental Remediation

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

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010- 2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the Federal Energy Regulatory Commission (FERC) to sell power to non-affiliates at market-based prices. The retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $16 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this

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Southern Company and Subsidiary Companies 2005 Annual Report

expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $31 million, of which $11 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are subject to refund to the extent the FERC orders any changes to the IIC.

     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund a total of $19 million previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. Southern Company has also received similar requests from other entities totaling approximately $14 million. Southern Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on Southern Company and the final results of these matters cannot be determined at this time.

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require Southern Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Market-Based Rate Authority” and “Generation Interconnection Agreements” above for additional

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Southern Company and Subsidiary Companies 2005 Annual Report

information. The final outcome of these proceedings cannot now be determined. However, Southern Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

PSC Matters

Alabama Power

In October 2004, the Alabama PSC approved a specific rate mechanism for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 1 percent in both January 2005 and 2006. In conjunction with the Alabama PSC’s approval of this rate mechanism, Alabama Power agreed to a moratorium until 2007 on any retail rate increase under its previously approved Rate Stabilization and Equalization Plan (Rate RSE).

     On October 4, 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates will remain unchanged if the return on equity (ROE) is between 13 percent and 14.5 percent. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006.

     See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information.

Georgia Power

In December 2004, the Georgia PSC approved the December 2004 three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan) for Georgia Power. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees were increased by approximately $203 million in January 2005 to cover the higher costs of purchased power, operation and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability.

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

     On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement. Savannah Electric will merge into Georgia Power, with Georgia Power continuing as the surviving corporation. Pending regulatory approvals, the merger is expected to occur by July 2006. See “Fuel Cost Recovery” herein and Note 3 to the financial statements under “Merger of Georgia Power and Savannah Electric” for additional information.

Mississippi Power

On December 1, 2005, Mississippi Power submitted its annual Performance Evaluation Plan (PEP) filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, Mississippi Power has requested that the Mississippi PSC approve a temporary change to allow it to exceed this cap as a result of the ongoing effects of Hurricane Katrina. Mississippi Power has requested a 5 percent, or $32 million, retail base rate increase to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.

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Southern Company and Subsidiary Companies 2005 Annual Report

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

Fuel Cost Recovery

The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past year, the retail operating companies have continued to experience higher than expected fuel costs for coal and natural gas. These higher fuel costs have increased the under recovered fuel costs included in the balance sheets. The retail operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. Each of the retail operating companies received approval in 2005 to increase their fuel cost recovery factors to recover existing under recovered amounts as well as projected future costs.

     Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In December 2005, the Alabama PSC approved an increase that allows for the recovery of approximately $227 million in existing under recovered fuel costs over a two-year period.

     In May 2005, the Georgia PSC approved Georgia Power’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with a Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. In connection with the proposed merger, Georgia Power has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, Georgia Power and Savannah Electric will file a combined request in March 2006 to increase its fuel cost recovery rate.

     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Georgia Power and Savannah Electric generating fleet as well as the under recovered balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all Georgia Power customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the merger will be paid by the appropriate customer groups.

     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. Georgia Power and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of these matters cannot now be determined.

     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow. Based on their respective state PSC orders, a portion of the under recovered regulatory clause revenues for Alabama Power, Georgia Power, and Savannah Electric was reclassified from current assets to deferred charges and other assets in the balance sheet. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 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 facilities and the cost of uninsured damages to its generation facilities and other property. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through Southern Company’s service territory causing substantial damage.

     At Gulf Power, the related costs charged to its property damage reserve as of December 31, 2004 were $93.5 million. Prior to Hurricane Ivan, Gulf Power’s reserve balance was approximately $28 million. Gulf Power’s current annual accrual to the property damage reserve, as approved by the Florida PSC, is $3.5 million. The Florida PSC has also approved additional accrual amounts at Gulf Power’s discretion; Gulf Power accrued an additional $6 million and $15 million in 2005 and 2004, respectively. In February 2005, Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group filed a Stipulation and Settlement with the Florida PSC, which the Florida PSC subsequently approved, allowing Gulf Power to recover the retail portion of $51.7 million of these costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. In connection with the stipulation, Gulf Power has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

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

     In February and December 2005, Alabama Power requested and received Alabama PSC approval of accounting orders that allowed Alabama Power to immediately return certain regulatory liabilities to the retail customers. These orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effect of these orders had no impact on net income in 2005.

     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused significant damage within Southern Company’s service area, including portions of the service areas of Alabama Power, Gulf Power, and Mississippi Power. The total incremental cost of repairing the damages to Mississippi Power’s facilities and restoring service to customers is currently estimated to be approximately $277 million net of approximately $68 million of insurance proceeds. Prior to Hurricane Katrina, Mississippi Power had a balance of approximately $3 million in its property reserve. Incremental costs incurred through December 31, 2005 were $210 million net of insurance proceeds of $68 million, of which $8 million has been received. These costs include approximately $149 million of capital additions and $133 million of operation and maintenance expenditures. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 Mississippi Power customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs or associated cost estimates. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.

     Each of the affected retail operating companies has been authorized by their respective state PSCs to defer the portion of the Hurricane Dennis and Katrina restoration costs that exceeded the balance in their storm damage reserve accounts. As of December 31, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $366 million, of which approximately $70 million and $296 million, respectively, is included in the balance sheets herein under Other Current Assets and Other Regulatory Assets. The recovery of these deferred

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

costs is subject to the approval of the respective state PSCs.

     In December 2005, the Alabama PSC approved a separate rate rider to recover Alabama Power’s $51 million of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish its reserve to a target balance of $75 million over a five-year period.

     In October 2005, the Mississippi PSC issued an Interim Accounting Order requiring Mississippi Power to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. In December 2005, Mississippi Power filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. Mississippi Power is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to federal grant assistance and proposed state legislation to allow securitized financing.

     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, Gulf Power filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over 8 years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve Gulf Power’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish Gulf Power’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. Since Gulf Power will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on net income, but would increase cash flow.

     See Notes 1 and 3 to the financial statements under “Storm Damage Reserves” and “Storm Damage Cost Recovery,” respectively, for additional information on these reserves. The final outcome of these matters cannot now be determined.

Mirant Bankruptcy Matters

Mirant is an energy company with businesses that include independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership and Mirant became an independent corporate entity.

     In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant). Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 to the financial statements under “Guarantees.”

     In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these tax items and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in the Chapter 11 proceeding. Based on management’s assessment of the collectibility of this receivable, Southern Company has reserved approximately $12.5 million. If Southern Company is ultimately required to make any additional payments, Mirant’s indemnification obligation to Southern Company for these additional payments would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant, the value of which is uncertain. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy.”

     In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability and that Southern Company caused Mirant to breach its fiduciary duties to creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the second amended complaint in February 2006. Also in February 2006, the Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy Litigation” for additional information. The ultimate outcome of these matters cannot be determined at this time.

Income Tax Matters

Leveraged Lease Transactions

Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years through 2001. Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. The IRS proposed to disallow the tax losses for one of these leases (a lease-in-lease-out, or LILO) in connection with its audit of 1996 through 2001. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS, which is subject to final approval.

     In connection with its audit of 2000 and 2001, the IRS also challenged Southern Company’s deductions related to three other international lease (sale-in-lease-out, or SILO) transactions. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company would be subject to additional interest charges of up to $34 million. The IRS has also proposed a penalty of approximately $16 million. Southern Company believes these transactions are valid leases for U.S. tax purposes, the related deductions are allowable, and the assessment of a penalty is inappropriate. Southern Company is continuing to pursue resolution of these matters with the IRS and expects to litigate the issue if necessary. Although the payment of the tax liability, exclusive of interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Through December 31, 2005, Southern Company has claimed $241 million in tax benefits related to these SILO transactions challenged by the IRS. See Note 1 to the financial statements under “Leveraged Leases” for additional information.

     Under current accounting rules, the settlement of the LILO transaction will not have a material impact on Southern Company’s financial statements; however, the Financial Accounting Standards Board (FASB) has proposed changes to the accounting for leveraged leases that are expected to become effective in 2006. If approved as proposed, these changes could require Southern Company to reflect the tax deductions that the IRS is challenging as currently payable in the balance sheet and to change the timing of income recognized for the leases, including a cumulative effect upon adoption of the change. For the LILO transaction settled with the IRS in February 2005, Southern Company estimates such cumulative effect would reduce Southern Company’s net income by up to $16 million. The impact of these proposed changes related to the SILO transactions would be dependent on the resolution of these matters with the IRS but could be significant, and potentially material, to Southern Company’s net income. The ultimate outcome of these matters cannot now be determined.

Synthetic Fuel Tax Credits

Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 45K (formerly Section 29) of the Internal Revenue Code of 1986, as amended

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

(Internal Revenue Code). In accordance with Section 45K of the Internal Revenue Code, these tax credits are subject to limitation as the annual average price of oil (as determined by the DOE) increases over a specified, inflation-adjusted dollar amount published in the spring of the subsequent year. Southern Company, along with its partners in these investments, will continue to monitor oil prices. Any indicated potential limitation on these credits could affect either the timing or the amount of the credit recognition and could also result in an impairment of these investments, which total approximately $19.5 million at December 31, 2005, by Southern Company.

Construction Projects

Integrated Coal Gasification Combined Cycle

In December 2005, Southern Power and the Orlando Utilities Commission (OUC) executed definitive agreements for development of an integrated coal gasification combined cycle (IGCC) 283-megawatt project in Orlando, Florida. The definitive agreements provide that Southern Power will own at least 65 percent of the gasifier portion of the IGCC project. OUC will own the remainder of the gasifier portion and 100 percent of the combined cycle portion of the IGCC project. OUC will purchase all of the gasifier capacity from Southern Power once the plant is in commercial operation. Southern Power will construct the project and manage its operation after construction is completed. In February 2006, Southern Power signed a cooperative agreement with the DOE that provides up to $235 million in grant funding for the gasification portion of this project. The IGCC project is subject to National Environmental Policy Act review as well as state environmental review, requires certain regulatory approvals, and is expected to begin commercial operation in 2010. Southern Power’s total cost related to the IGCC project is estimated at approximately $121 million.

Plant Franklin Unit 3

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

Nuclear

As part of a potential expansion of Plant Vogtle, Georgia Power and Southern Nuclear have notified the Nuclear Regulatory Commission (NRC) of their intent to apply for an early site permit (ESP) this year and a combined construction and operating license (COL) in 2008. In addition, a reactor design from Westinghouse Electric Company has been selected and a purchase agreement is being negotiated. Participation agreements have been reached with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. At this point, no final decision has been made regarding actual construction. The NRC’s streamlined licensing process for new nuclear units allows utilities to seek regulatory approval at various stages. These stages include design certification, which is obtained by the reactor vendor, and the ESP and COL, which are each obtained by the owner-operators of the units. An ESP indicates site approval is obtained before a company decides to build and the COL provides regulatory approval for building and operating the plant. In addition, any new Georgia Power generation must be certified by the Georgia PSC.

     Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy plans to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs, then to choose one of the applications and file it for NRC review and approval. The COL ultimately is expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.

     Southern Company is also exploring other possibilities relating to nuclear power projects, both on its own or in partnership with other utilities.

Other Matters

In accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, Southern Company recorded non-cash pre-tax pension income/(expense) of approximately $(2) million, $44 million, and $99 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for Southern Company were $118 million, $106 million, and $101 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. For the retail operating companies, pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

Southern Company’s retail operating companies, which comprise approximately 88 percent of Southern Company’s total earnings for 2005, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the retail operating companies are permitted to charge customers based on allowable costs. As a result, the retail operating companies apply FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the retail operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

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

Contingent Obligations

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

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

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

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

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

Unbilled Revenues

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

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. Southern Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, Southern Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, Southern Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” At December 31, 2005, Southern Company recorded additional asset retirement obligations (and assets) of approximately $153 million. The adoption of FIN 47 did not have any effect on Southern Company’s income statement.

Stock Options

On January 1, 2006, Southern Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition continued to be stable at December 31, 2005. Net cash flow from operating activities totaled $2.5 billion, $2.7 billion, and $3.1 billion for 2005, 2004, and 2003, respectively. The $165 million decrease for 2005 resulted primarily from higher fuel costs at the retail operating companies, partially offset by increases in base rates and fuel recovery rates. The $376 million decrease from 2003 to 2004 also resulted primarily from higher fuel costs at the retail operating companies. Fuel costs are recoverable in future periods and are reflected in the balance sheets as under recovered regulatory clause revenues. See

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information.

     Significant balance sheet changes include a $0.4 billion increase in long-term debt and preferred stock for 2005 due to an increase of $1.1 billion in property, plant, and equipment. The majority of funds needed for property additions were provided from operating activities.

     At the close of 2005, the closing price of Southern Company’s common stock was $34.53 per share, compared with book value of $14.42 per share. The market-to-book value ratio was 240 percent at the end of 2005, compared with 242 percent at year-end 2004.

     Each of the retail operating companies, Southern Power, and SCS have received investment grade ratings from the major rating agencies.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2006, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The Company does not currently anticipate any equity offerings in 2006 outside of its existing stock option plan.

     The retail operating companies plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, and term loan and short-term borrowings. Gulf Power and Mississippi Power are considering other financing options for storm recovery costs. However, the type and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by the retail operating companies is generally subject to the approval of the applicable state PSC. In addition, the issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power and Savannah Electric is generally subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

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

     Southern Company and each retail operating company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company.

     Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has various sources of liquidity. In addition, Southern Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.

     At December 31, 2005, Southern Company and its subsidiaries had approximately $202 million of cash and cash equivalents and $3.3 billion of unused credit arrangements with banks, of which $810 million expire in 2006 and $2.5 billion expire in 2007 and beyond. Approximately $228 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional two-year period, and $311 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. See Note 6

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

to the financial statements under “Bank Credit Arrangements” for additional information.

Financing Activities

During 2005, Southern Company and its subsidiaries issued $1.6 billion of long-term debt and $55 million of preference stock. The security issuances were used to redeem $1.3 billion of long-term debt, to fund Southern Company’s ongoing construction program, and for general corporate purposes. In addition, Southern Company issued 10.1 million new shares of common stock through the Company’s stock plans and realized proceeds of $213 million. In a program designed primarily to offset these issuances, Southern Company also repurchased 10.1 million shares of common stock at a total cost of $352 million. The repurchase program was discontinued in early January 2006.

     Subsequent to December 31, 2005, Alabama Power issued $600 million of long-term senior notes to reduce short-term debt and for other general corporate purposes. In conjunction with these transactions, Alabama Power terminated $600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period. In addition, Southern Company redeemed $72 million in long-term debt payable to affiliated trusts following the repurchase of the underlying capital securities.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $196.4 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $602.3 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Southern Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, Southern Company and its subsidiaries had no material exposure under these contracts.

     Subsequent to December 31, 2005, the Company has entered into additional physical electricity purchases and sales contracts adding $9 million to the maximum potential collateral requirements at a credit rating of BBB and Baa2 and $17 million at BBB- or Baa3 and below.

Market Price Risk

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

     To mitigate future exposure to change in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. These swaps have a notional amount of $930 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $1.5 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.37 percent. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $15.4 million at January 1, 2006. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

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

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

	Changes in Fair Value
	2005			2004
	(in millions)
Contracts beginning of year	$	10.5		$	15.8
Contracts realized or settled		(106.1	)		(58.7	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		196.1			53.4
Contracts end of year	$	100.5		$	10.5

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

Source of 2005 Year-End Valuation Prices
	Total			Maturity
	Fair Value			2006			2007-2008
	(in millions)
Actively quoted	$	101.6		$	67.6		$	34.0
External sources		(1.1	)		(1.1	)		—
Models and other		—			—			—
Contracts end of year	$	100.5		$	66.5		$	34.0

     Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the retail operating companies’ fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the retail operating companies’ fuel cost recovery clauses. In addition, unrealized gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are deferred in other comprehensive income. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in millions)
Regulatory liabilities, net	$	103.4
Other comprehensive income		(0.3	)
Net income		(2.6	)
Total fair value	$	100.5

     Unrealized pre-tax gains and losses recognized in income were not material for any year presented.

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

Capital Requirements and Contractual Obligations

The construction program of Southern Company is currently estimated to be $2.8 billion for 2006, $3.6

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

billion for 2007, and $3.1 billion for 2008. Environmental expenditures included in these amounts are $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

     As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also, as discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants, to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The final installment is scheduled to occur in 2006.

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Contractual Obligations

			2007-		2009-		After
	2006		2008		2010		2010		Total
	(in millions)
Long-term debt(a) –
Principal	$	901	$	1,966	$	834	$	—	$	3,701
Interest		688		1,246		1,108		9,752		12,794
Other derivative obligations(b) –
Commodity		32		—		—		—		32
Preferred and preference stock dividends(c)		33		65		65		—		163
Operating leases		123		205		156		259		743
Purchase commitments(d) –
Capital(e)		2,772		6,673		—		—		9,445
Coal		3,129		3,959		1,558		364		9,010
Nuclear fuel		63		62		34		89		248
Natural gas(f)		1,495		1,286		740		3,046		6,567
Purchased power		175		356		305		541		1,377
Long-term service agreements		71		175		180		1,334		1,760
Trusts –
Nuclear decommissioning		7		14		14		117		152
Postretirement benefits(g)		45		88		—		—		133
DOE		9		—		—		—		9
Total	$	9,543	$	16,095	$	4,994	$	15,502	$	46,134

(a)	All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
(b)	For additional information, see Notes 1 and 6 to the financial statements.
(c)	Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(d)	Southern Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $3.5 billion, $3.3 billion, and $3.2 billion, respectively.
(e)	Southern Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)	Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)	Southern Company forecasts postretirement trust contributions over a three-year period. No contributions related to Southern Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from Southern Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, retail sales growth, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, dividend payout ratios, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and Georgia Power, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

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

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

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

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

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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2003
	(in millions)
Operating Revenues:
Retail sales	$	11,165		$	9,732		$	8,875
Sales for resale		1,667			1,341			1,358
Other electric revenues		446			392			514
Other revenues		276			264			271
Total operating revenues		13,554			11,729			11,018
Operating Expenses:
Fuel		4,495			3,399			2,999
Purchased power		731			643			473
Other operations		2,394			2,263			2,177
Maintenance		1,116			1,027			937
Depreciation and amortization		1,176			949			1,022
Taxes other than income taxes		680			627			586
Total operating expenses		10,592			8,908			8,194
Operating Income		2,962			2,821			2,824
Other Income and (Expense):
Allowance for equity funds used during construction		51			47			25
Interest income		36			27			36
Equity in losses of unconsolidated subsidiaries		(119	)		(95	)		(99	)
Leveraged lease income		74			70			66
Interest expense, net of amounts capitalized		(619	)		(540	)		(527	)
Interest expense to affiliate trusts		(128	)		(100	)		—
Distributions on mandatorily redeemable preferred securities		—			(27	)		(151	)
Preferred dividends of subsidiaries		(30	)		(30	)		(21	)
Other income (expense), net		(41	)		(59	)		(52	)
Total other income and (expense)		(776	)		(707	)		(723	)
Earnings From Continuing Operations Before Income Taxes		2,186			2,114			2,101
Income taxes		595			585			618
Earnings From Continuing Operations		1,591			1,529			1,483
Earnings from discontinued operations, net of income taxes of $-, $2, and $(6) for 2005, 2004, and 2003, respectively		—			3			(9	)
Consolidated Net Income	$	1,591		$	1,532		$	1,474
Common Stock Data:
Earnings per share from continuing operations—
Basic	$	2.14		$	2.07		$	2.04
Diluted		2.13			2.06			2.03
Earnings per share including discontinued operations—
Basic	$	2.14		$	2.07		$	2.03
Diluted		2.13			2.06			2.02
Average number of shares of common stock outstanding — (in millions)
Basic		744			739			727
Diluted		749			743			732
Cash dividends paid per share of common stock	$	1.475		$	1.415		$	1.385

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

II-38

CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report

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

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

II-39

CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report

Liabilities and Stockholders’ Equity	2005		2004
	(in millions)
Current Liabilities:
Securities due within one year	$	901	$	983
Notes payable		1,258		426
Accounts payable		1,229		877
Customer deposits		220		199
Accrued taxes —
Income taxes		104		47
Other		319		242
Accrued interest		204		179
Accrued vacation pay		144		137
Accrued compensation		459		424
Other		402		284
Total current liabilities		5,240		3,798
Long-term Debt(See accompanying statements)		10,958		10,488
Long-term Debt Payable to Affiliated Trusts(See accompanying statements)		1,888		1,961
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		5,736		5,243
Deferred credits related to income taxes		311		373
Accumulated deferred investment tax credits		527		552
Employee benefit obligations		930		864
Asset retirement obligations		1,117		903
Other cost of removal obligations		1,295		1,296
Other regulatory liabilities		323		328
Other		267		310
Total deferred credits and other liabilities		10,506		9,869
Total Liabilities		28,592		26,116
Preferred and Preference Stock of Subsidiaries(See accompanying statements)		596		561
Common Stockholders’ Equity(See accompanying statements)		10,689		10,278
Total Liabilities and Stockholders’ Equity	$	39,877	$	36,955
Commitments and Contingent Matters(See notes)

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

II-40

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2003
	(in millions)
Operating Activities:
Consolidated net income	$	1,591		$	1,532		$	1,474
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization		1,398			1,161			1,281
Deferred income taxes and investment tax credits		499			559			427
Storm damage accounting order		48			—			—
Allowance for equity funds used during construction		(51	)		(47	)		(25	)
Equity in losses of unconsolidated subsidiaries		119			95			99
Leveraged lease income		(74	)		(70	)		(66	)
Pension, postretirement, and other employee benefits		(6	)		(22	)		(40	)
Tax benefit of stock options		50			31			30
Hedge settlements		(19	)		(10	)		(116	)
Other, net		(22	)		37			32
Changes in certain current assets and liabilities —
Receivables		(1,045	)		(392	)		(11	)
Fossil fuel stock		(110	)		(8	)		(17	)
Materials and supplies		(78	)		(31	)		(12	)
Other current assets		(1	)		9			26
Accounts payable		71			29			(88	)
Accrued taxes		28			(109	)		19
Accrued compensation		13			(23	)		(11	)
Other current liabilities		119			(46	)		69
Net cash provided from operating activities		2,530			2,695			3,071
Investing Activities:
Property additions		(2,370	)		(2,022	)		(1,964	)
Nuclear decommissioning trust fund purchases		(606	)		(810	)		(1,007	)
Nuclear decommissioning trust fund sales		596			781			978
Investment in unconsolidated subsidiaries		(115	)		(97	)		(94	)
Cost of removal net of salvage		(128	)		(75	)		(80	)
Other		(6	)		(35	)		(27	)
Net cash used for investing activities		(2,629	)		(2,258	)		(2,194	)
Financing Activities:
Increase (decrease) in notes payable, net		831			(141	)		(366	)
Proceeds —
Long-term debt		1,608			1,861			3,494
Mandatorily redeemable preferred securities		—			200			—
Preferred and preference stock		55			175			125
Common stock		213			124			470
Redemptions —
Long-term debt		(1,285	)		(1,246	)		(3,009	)
Mandatorily redeemable preferred securities		—			(240	)		(480	)
Preferred and preference stock		(4	)		(28	)		—
Common stock repurchased		(352	)		—			—
Payment of common stock dividends		(1,098	)		(1,045	)		(1,004	)
Other		(35	)		(40	)		(69	)
Net cash (used for) provided from financing activities		(67	)		(380	)		(839	)
Net Change in Cash and Cash Equivalents		(166	)		57			38
Cash and Cash Equivalents at Beginning of Year		368			311			273
Cash and Cash Equivalents at End of Year	$	202		$	368		$	311

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

II-41

CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report

		2005			2004			2005			2004
		(in millions)						(percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds —
Maturity	Interest Rates
2006	6.50% to 6.90%	$	45		$	45
2025 through 2026	6.88% to 7.45%		—			60
Total first mortgage bonds			45			105
Long-term senior notes and debt —
Maturity	Interest Rates
2005	5.49% to 5.50%		—			379
2006	2.65% to 6.20%		674			674
2007	3.50% to 7.13%		1,207			1,220
2008	2.54% to 6.55%		461			462
2009	4.10% to 7.00%		128			169
2010	4.70%		102			102
2011 through 2044	4.00% to 8.12%		5,637			4,433
Adjustable rates (at 1/1/06):
2005	1.66% to 3.63%		—			563
2006	2.11%		27			195
2007	2.11% to 5.755		265			90
2009	4.53% to 4.64%		440			440
2010	5.41%		154			—
Total long-term senior notes and debt			9,095			8,727
Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
Collateralized:
2006	5.25%		12			12
2024	5.50%		3			24
Variable rates (at 1/1/06):
2015 through 2017	2.01% to 2.16%		90			90
Non-collateralized:
2012 through 2034	2.83% to 5.45%		850			850
Variable rates (at 1/1/06):
2011 through 2038	2.01% to 3.87%		1,586			1,565
Total other long-term debt			2,541			2,541
Capitalized lease obligations			110			115
Unamortized debt (discount), net			(19	)		(17	)
Total long-term debt (annual interest requirement — $561 million)			11,772			11,471
Less amount due within one year			814			983
Long-term debt excluding amount due within one year			10,958			10,488			45.4	%		45.1	%

II-42

CONSOLIDATED STATEMENTS OF CAPITALIZATION(continued)
At December 31, 2005 and 2004
Southern Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2005			2004
	(in millions)						(percent of total)
Long-term Debt Payable to Affiliated Trusts:
Maturity                      Interest Rates
2027 through 2044       4.75% to 8.19%
(annual interest requirement — $128 million)		1,960			1,961
Less amount due within one year		72			—
Total long-term debt payable to affiliated trusts excluding amount due within one year		1,888			1,961			7.8			8.4
Preferred and Preference Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 5.44%
Authorized — 20 million shares
Outstanding — 1 million shares		96			100
$1 par value — 4.95% to 5.83%
Authorized — 28 million shares
Outstanding — 12 million shares: $25 stated value		294			294
Outstanding — 1,250 shares: $100,000 stated value		123			123
Non-cumulative preferred stock
$25 par or stated value — 6.00%
Authorized — 4 million shares
Outstanding — 2 million shares		44			44
Non-cumulative preference stock
$100 par or stated value — 6.00%
Authorized — 10 million shares
Outstanding — 1 million shares		54			—
Total preferred and preference stock of subsidiaries
(annual dividend requirement — $33 million)		611			561
Less amount due within one year		15			—
Preferred and preference stock of subsidiaries excluding amount due within one year		596			561			2.5			2.4
Common Stockholders’ Equity:
Common stock, par value $5 per share —		3,759			3,709
Authorized — 1 billion shares
Issued — 2005: 752 million shares
— 2004: 742 million shares
Treasury — 2005: 10.4 million shares
— 2004: 0.2 million shares
Paid-in capital		1,085			869
Treasury, at cost		(359	)		(6	)
Retained earnings		6,332			5,839
Accumulated other comprehensive income (loss)		(128	)		(133	)
Total common stockholders’ equity		10,689			10,278			44.3			44.1
Total Capitalization	$	24,131		$	23,288			100.0	%		100.0	%

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

II-43

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report

											Accumulated
											Other Comprehensive
	Common Stock										Income (Loss)
	Par		Paid-In					Retained			Continuing			Discontinued
	Value		Capital		Treasury			Earnings			Operations			Operations			Total
	(in millions)
Balance at December 31, 2002	$	3,583	$	338	$	(3	)	$	4,874		$	(95	)	$	13		$	8,710
Net income		—		—		—			1,474			—			—			1,474
Other comprehensive income (loss)		—		—		—			—			(20	)		(11	)		(31	)
Stock issued		92		408		—			—			—			—			500
Cash dividends		—		—		—			(1,004	)		—			—			(1,004	)
Other		—		1		(1	)		(1	)		—			—			(1	)
Balance at December 31, 2003		3,675		747		(4	)		5,343			(115	)		2			9,648
Net income		—		—		—			1,532			—			—			1,532
Other comprehensive income (loss)		—		—		—			—			(16	)		(4	)		(20	)
Stock issued		34		122		—			—			—			—			156
Cash dividends		—		—		—			(1,044	)		—			—			(1,044	)
Other		—		—		(2	)		8			—			—			6
Balance at December 31, 2004		3,709		869		(6	)		5,839			(131	)		(2	)		10,278
Net income		—		—		—			1,591			—			—			1,591
Other comprehensive income (loss)		—		—		—			—			3			2			5
Stock issued		50		216		—			—			—			—			266
Stock repurchased, at cost		—		—		(352	)		—			—			—			(352	)
Cash dividends		—		—		—			(1,098	)		—			—			(1,098	)
Other		—		—		(1	)		—			—			—			(1	)
Balance at December 31, 2005	$	3,759	$	1,085	$	(359	)	$	6,332		$	(128	)	$	—		$	10,689

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2003
	(in millions)
Consolidated Net Income	$	1,591		$	1,532		$	1,474
Other comprehensive income (loss) — continuing operations:
Change in additional minimum pension liability, net of tax of $(6), $(11), and $(11), respectively		(11	)		(20	)		(17	)
Change in fair value of marketable securities, net of tax of $(2) and $4, respectively		(4	)		6			—
Changes in fair value of qualifying hedges, net of tax of $7, $(11), and $(12), respectively		12			(16	)		(20	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $4, $8, and $9, respectively		6			14			17
Total other comprehensive income (loss) — continuing operations		3			(16	)		(20	)
Other comprehensive income (loss) — discontinued operations:
Changes in fair value of qualifying hedges, net of tax of $4, $(1), and $10, respectively		6			(2	)		3
Less: Reclassification adjustment for amounts included in net income, net of tax of $(3), $(1), and $(8), respectively		(4	)		(2	)		(14	)
Total other comprehensive income (loss) — discontinued operations		2			(4	)		(11	)
Consolidated Comprehensive Income	$	1,596		$	1,512		$	1,443

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

II-44

NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

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

     On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary, including natural gas inventory, accounts receivable, and customer list, to Gas South, LLC, an affiliate of Cobb Electric Membership Corporation. As a result of the sale, Southern Company’s financial statements and related information reflect Southern Company Gas as discontinued operations. For additional information, see Note 3 under “Southern Company Gas Sale.”

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

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and the Company and its subsidiaries were subject to the regulatory provisions of the PUHCA. The retail operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the FERC and the retail operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow accounting principles generally accepted in the United States and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Related Party Transactions

Alabama Power and Georgia Power purchase synthetic fuel from Alabama Fuel Products, LLC (AFP), an entity in which Southern Holdings holds a 30 percent ownership interest. Total fuel purchases for 2005, 2004, and 2003 were $507 million, $409 million, and $312 million, respectively. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings, provides fuel transportation services to AFP that are ultimately reflected in the cost of the synthetic fuel billed to Alabama Power and Georgia Power. In connection with these services, the related revenues of approximately $83 million, $82 million, and $65 million in 2005, 2004, and 2003, respectively, have been eliminated against fuel expense in the financial statements. SSI also provides additional services to AFP, as well as to a related party of AFP. Revenues from these transactions totaled approximately $40 million, $24 million, and $20 million in 2005, 2004, and 2003, respectively.

II-45

NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Regulatory Assets and Liabilities

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

	2005			2004			Note
	(in millions)
Deferred income tax charges	$	937		$	865			(a	)
Asset retirement obligations — asset.		81			7			(a	)
Asset retirement obligations — liab.		(139	)		(180	)		(a	)
Other cost of removal obligations		(1,295	)		(1,296	)		(a	)
Deferred income tax credits		(313	)		(374	)		(a	)
Loss on reacquired debt		309			323			(b	)
Vacation pay		109			105			(c	)
Building lease		52			53			(d	)
Generating plant outage costs — asset		54			49			(d	)
Storm damage — asset		366			97			(d	)
Fuel hedging		(116	)		(27	)		(d	)
Other assets		139			115			(d	)
Environmental remediation — asset		58			59			(d	)
Environmental remediation — liab.		(36	)		(47	)		(d	)
Deferred purchased power		(52	)		(19	)		(d	)
Other liabilities		(32	)		(26	)		(d	)
Plant Daniel capacity		(19	)		(44	)		(e	)
Total	$	103		$	(340	)

Note:	The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
(c)	Recorded as earned by employees and recovered as paid, generally within one year.
(d)	Recorded and recovered or amortized as approved by the appropriate state PSCs.
(e)	Amortized over four-year period ending in 2007.

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

Revenues

Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the retail operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.

     Retail fuel costs recovery mechanisms vary by each retail operating company, but in general, the process requires periodic filings with the appropriate state PSC. Alabama Power continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. The Georgia PSC requires that such amounts be reviewed semi-annually. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power is required to file for a temporary fuel rate change. If the over or under recovery exceeds 10 percent of the projected fuel costs for the period, Gulf Power is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary. Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually. See “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” in Note 3 for additional information.

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

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased

II-46

NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $134 million in 2005, $134 million in 2004, and $138 million in 2003.

Nuclear Fuel Disposal Costs

Alabama Power and Georgia Power have contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is scheduled to begin in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry storage facilities are operational and can be expanded to accommodate spent fuel through the life of each plant.

     Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment has been paid over a 15-year period; the final installment is scheduled to occur in 2006. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. Alabama Power and Georgia Power, based on its ownership interest, estimate their respective remaining liability at December 31, 2005 under this law to be approximately $5 million and $4 million.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

     Southern Company’s property, plant, and equipment consisted of the following at December 31 (in millions):

	2005		2004
Generation	$	22,490	$	21,262
Transmission		6,031		5,770
Distribution		11,894		11,368
General		2,393		2,268
Plant acquisition adjustment		41		42
Utility plant in service		42,849		40,710
IT equipment and software		211		214
Communications equipment		431		404
Other		87		97
Other plant in service		729		715
Total plant in service	$	43,578	$	41,425

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

Income Taxes

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

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2005, 3.0 percent in 2004, and 3.1 percent in 2003. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the retail operating companies. Accumulated depreciation for utility plant in service totaled $15.3 billion and $14.6 billion at December 31, 2005 and

II-47

NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

2004, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

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

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

     Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from 3 to 25 years. Accumulated depreciation for other plant in service totaled $378 million and $345 million at December 31, 2005 and 2004, respectively.

Asset Retirement Obligations
and Other Costs of Removal

Effective January 1, 2003, Southern Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, Southern Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or Interpretation No. 47.

     The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, Plants Farley, Hatch, and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2005 was $954 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, Southern Company also recorded additional asset retirement obligations (and assets) of approximately $153 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue

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Southern Company and Subsidiary Companies 2005 Annual Report

to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

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

	2005			2004
	(in millions)
Balance beginning of year	$	903		$	845
Liabilities incurred		155			—
Liabilities settled		(2	)		(3	)
Accretion		61			57
Cash flow revisions		—			4
Balance end of year	$	1,117		$	903

     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $1.0 billion.

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:

	Unrealized		Unrealized			Fair
2005	Gains		Losses			Value
			(in millions)
Equity	$	155.6	$	(14.0	)	$	600.8
Debt		4.1		(2.4	)		241.4
Other		17.0		—			111.4
Total	$	176.7	$	(16.4	)	$	953.6

	Unrealized		Unrealized			Fair
2004	Gains		Losses			Value
			(in millions)
Equity	$	140.0	$	(8.3	)	$	566.3
Debt		8.5		(0.7	)		233.5
Other		13.6		(0.2	)		105.0
Total	$	162.1	$	(9.2	)	$	904.8

     The contractual maturities of debt securities at December 31, 2005 are as follows: $17.3 million in 2006; $90.1 million in 2007-2010; $59.5 million in 2011-2015; and $65.5 million thereafter.

     Sales of the securities held in the trust funds resulted in proceeds of $596.3 million, $781.3 million, and $978.1 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $22.5 million, $21.6 million, and $19.6 million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and did not require the recognition of any impairment related to the underlying investments.

     Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the respective state PSCs. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2005, the accumulated provisions for decommissioning were as follows:

	Plant		Plant		Plant
	Farley		Hatch		Vogtle
			(in millions)
External trust funds, at fair value	$	467	$	313	$	174
Internal reserves		28		—		1
Total	$	495	$	313	$	175

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Southern Company and Subsidiary Companies 2005 Annual Report

     Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current studies, which were performed in 2003, for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle were as follows:

	Plant		Plant		Plant
	Farley		Hatch		Vogtle
Decommissioning periods:
Beginning year		2017		2034		2027
Completion year		2046		2065		2048
	(in millions)
Site study costs:
Radiated structures	$	892	$	497	$	452
Non-radiated structures		63		49		58
Total	$	955	$	546	$	510

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

     For ratemaking purposes, Alabama Power’s decommissioning costs are based on the site study and Georgia Power’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2003, $421 million and $326 million for Plants Hatch and Vogtle, respectively. Amounts expensed in 2005, 2004, and 2003 totaled $7 million, $27 million, and $27 million, respectively. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and 3.1 percent for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0 percent and 5.1 percent for Alabama Power and Georgia Power, respectively. Another significant assumption used was the change in the operating licenses for Plants Farley and Hatch. In January 2002, the NRC granted Georgia Power a 20-year extension of the licenses for both units at Plant Hatch, which permits the operation of units 1 and 2 until 2034 and 2038, respectively.

     In May 2005, the NRC granted Alabama Power a similar 20-year extension of the operating license for both units at Plant Farley. As a result of the Farley license extension, amounts previously contributed to the external trust fund are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved Alabama Power’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust fund. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of trust funds to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with NRC and other applicable requirements. The approved suspension would not affect the transfer of internal reserves (less than $1 million annually) to the external trust over the remaining life of the licenses.

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

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

     Cash payments for interest totaled $661 million, $551 million, and $603 million in 2005, 2004, and 2003, respectively, net of amounts capitalized of $21 million, $36 million, and $49 million, respectively.

Impairment of Long-Lived Assets and Intangibles

Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair

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Southern Company and Subsidiary Companies 2005 Annual Report

value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Storm Damage Reserves

Each retail operating company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to transmission and distribution facilities and to generation facilities and other property. In accordance with their respective state PSC orders, the retail operating companies accrued $15 million in 2005 that is recoverable through base rates. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2005, 2004, and 2003, such additional accruals totaled $6 million, $25 million, and $8 million, respectively. See Note 3 under “Storm Damage Recovery” for additional information regarding the depletion of these reserves following Hurricanes Ivan, Dennis, and Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which may be approved by the respective state PSCs to replenish these reserves.

Environmental Cost Recovery

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

     Georgia Power continues to recover environmental costs through its base rates. Beginning in 2005, such rates include an annual accrual of $5.4 million. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings. Under Georgia PSC ratemaking provisions, $22 million had previously been deferred in a regulatory liability account for use in meeting future environmental remediation costs of Georgia Power and is being amortized over a three-year period that began in January 2005.

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

     For Southern Company, the environmental remediation liabilities balances as of December 31, 2005 and 2004 totaled $62 million and $63 million, respectively.

Leveraged Leases

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

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

	2005			2004
	(in millions)
Net rentals receivable	$	509		$	457
Unearned income		(280	)		(283	)
Investment in leveraged leases		229			174
Deferred taxes arising from leveraged leases		(59	)		(32	)
Net investment in leveraged leases	$	170		$	142

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

	2005			2004			2003
				(in millions)
Pretax leveraged lease income	$	23		$	17		$	11
Income tax expense		(11	)		(8	)		(4	)
Net leveraged lease income	$	12		$	9		$	7

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Southern Company and Subsidiary Companies 2005 Annual Report

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

	2005			2004
	(in millions)
Net rentals receivable	$	1,298		$	1,298
Unearned income		(445	)		(496	)
Investment in leveraged leases		853			802
Deferred taxes arising from leveraged leases		(351	)		(360	)
Net investment in leveraged leases	$	502		$	442

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

	2005			2004			2003
				(in millions)
Pretax leveraged lease income	$	51		$	53		$	55
Income tax expense		(18	)		(19	)		(19	)
Net leveraged lease income	$	33		$	34		$	36

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options

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

     For pro forma purposes, Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on earnings from continuing operations is as follows:

	As		Options			Pro
	Reported		Impact			Forma
2005
Net income (in millions)	$	1,591	$	(17	)	$	1,574
Earnings per share (dollars):
Basic	$	2.14	$	(0.02	)	$	2.12
Diluted	$	2.13	$	(0.03	)	$	2.10
2004
Net income (in millions)	$	1,529	$	(16	)	$	1,513
Earnings per share (dollars):
Basic	$	2.07	$	(0.02	)	$	2.05
Diluted	$	2.06	$	(0.02	)	$	2.04
2003
Net income (in millions)	$	1,483	$	(17	)	$	1,466
Earnings per share (dollars):
Basic	$	2.04	$	(0.02	)	$	2.02
Diluted	$	2.03	$	(0.03	)	$	2.00

     The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:

	2005			2004			2003
Interest rate		3.9	%		3.1	%		2.7	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.9	%		19.6	%		23.6	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

Financial Instruments

Southern Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value.

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Southern Company and Subsidiary Companies 2005 Annual Report

Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the retail operating companies’ fuel hedging programs. This results in the deferral of related gains and losses in other comprehensive income or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.

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

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

	Carrying		Fair
	Amount		Value
	(in millions)
Long-term debt:
2005	$	13,623	$	13,633
2004		13,317		13,560

     The fair values were based on either closing market price or closing price of comparable instruments.

Comprehensive Income

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

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Southern Company has established certain wholly-owned trusts established to issue preferred securities. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the retail operating companies are not the primary beneficiaries of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts in the balance sheets.

     In addition, Southern Company holds an 85 percent limited partnership investment in an energy/technology venture capital fund that is consolidated in the financial statements. During the third quarter of 2004, Southern Company terminated new investments in this fund; however, additional contributions to existing investments will still occur. Southern Company has committed to a maximum investment of $50 million. At December 31, 2005, Southern Company’s investment totaled $25.6 million.

2. RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees. The retail operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately $45 million.

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

Pension Plans

The total accumulated benefit obligation for the pension plans was $5.2 billion in 2005 and $4.6 billion

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Southern Company and Subsidiary Companies 2005 Annual Report

in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

	Projected
	Benefit Obligations
	2005			2004
	(in millions)
Balance at beginning of year	$	5,075		$	4,573
Service cost		138			128
Interest cost		286			270
Benefits paid		(214	)		(207	)
Plan amendments		32			6
Actuarial (gain) loss		240			305
Balance at end of year	$	5,557		$	5,075

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	5,476		$	5,159
Actual return on plan assets		866			501
Employer contributions		19			23
Benefits paid		(214	)		(207	)
Balance at end of year	$	6,147		$	5,476

     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $5.2 billion and $0.4 billion, respectively. All plan assets are related to the qualified plan.

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

	Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	590		$	401
Unrecognized transition amount		(6	)		(14	)
Unrecognized prior service cost		293			292
Unrecognized net (gain) loss		3			185
Prepaid pension asset, net	$	880		$	864

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

	2005			2004
	(in millions)
Prepaid pension asset	$	1,022		$	986
Employee benefit obligations		(310	)		(280	)
Other property and investments		43			50
Accumulated other comprehensive income		125			108
Prepaid pension asset, net	$	880		$	864

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

	2005			2004			2003
	(in millions)
Service cost	$	138		$	128		$	115
Interest cost		286			269			261
Expected return on plan assets		(456	)		(452	)		(450	)
Recognized net gain		10			(7	)		(42	)
Net amortization		24			18			17
Net pension cost (income)	$	2		$	(44	)	$	(99	)

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	(in millions)
2006	$	222
2007		230
2008		238
2009		248
2010		262
2011 to 2015		1,596

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

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Southern Company and Subsidiary Companies 2005 Annual Report

	Accumulated
	Benefit Obligations
	2005			2004
	(in millions)
Balance at beginning of year	$	1,712		$	1,655
Service cost		28			27
Interest cost		96			93
Benefits paid		(78	)		(68	)
Actuarial (gain) loss		68			72
Plan amendments		—			(67	)
Balance at end of year	$	1,826		$	1,712

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	592		$	522
Actual return on plan assets		78			64
Employer contributions		92			74
Benefits paid		(78	)		(68	)
Balance at end of year	$	684		$	592

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

				Plan Assets
	Target			2005			2004
Domestic equity		44	%		46	%		43	%
International equity		17			18			18
Fixed income		29			29			32
Real estate		6			5			4
Private equity		4			2			3
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	(1,142	)	$	(1,120	)
Unrecognized transition obligation		114			129
Unrecognized prior service cost		121			130
Unrecognized net loss (gain)		428			408
Fourth quarter contributions		40			30
Accrued liability recognized in the balance sheets	$	(439	)	$	(423	)

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

	2005			2004			2003
	(in millions)
Service cost	$	28		$	28		$	25
Interest cost		97			93			93
Expected return on plan assets		(45	)		(50	)		(47	)
Net amortization		38			35			30
Net postretirement cost	$	118		$	106		$	101

     In the third quarter 2004, Southern Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced Southern Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $10.6 million and $26 million, respectively, and is expected to have a similar impact on future expenses.

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

	Benefit		Subsidy
	Payments		Receipts			Total
	(in millions)
2006	$	86	$	(7	)	$	79
2007		92		(9	)		83
2008		100		(10	)		90
2009		110		(11	)		99
2010		119		(12	)		107
2011 to 2015		668		(88	)		580

Actuarial Assumptions

     The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:

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	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00			3.50			3.75
Long-term return on plan assets		8.50			8.50			8.50

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	149	$	132
Service and interest costs		10		9

Employee Savings Plan

Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $58 million, $56 million, and $55 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

Mirant Matters

Mirant Corporation (Mirant) is an energy company with businesses that include independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.

Mirant Bankruptcy

In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization on December 9, 2005, and Mirant announced that this plan became effective on January 3, 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).

     Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 under “Guarantees” and with various lawsuits related to Mirant discussed below. Southern Company has paid approximately $1.4 million in connection with the guarantees. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Based on management’s assessment of the collectibility of this receivable, Southern Company has reserved approximately $12.5 million.

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     Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant, the value of which is uncertain. The final outcome of this matter cannot now be determined.

Mirant Bankruptcy Litigation

In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends include without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80 percent interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer Mirant asserts is valued at $248 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company caused Mirant to breach its fiduciary duties to creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the second amended complaint in February 2006.

     On December 29, 2005, the Bankruptcy Court entered an order transferring this proceeding, along with certain other actions, to a special purpose subsidiary of Reorganized Mirant. Under the order, Reorganized Mirant is obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits will be distributed to and shared equally by the unsecured creditors and the original equity holders.

     On January 10, 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court, and on February 15, 2006 granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. However, the final outcome of this matter cannot now be determined.

Mirant Securities Litigation

In November 2002, Southern Company, certain former and current senior officers of Southern Company, and 12 underwriters of Mirant’s initial public offering were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. Several other similar lawsuits filed subsequently were consolidated into this litigation in the U.S. District Court for the Northern District of Georgia. The amended complaint is based on allegations related to alleged improper energy trading and marketing activities involving the California energy market, alleged false statements and omissions in Mirant’s prospectus for its initial public offering and in subsequent public statements by Mirant, and accounting-related issues previously disclosed by Mirant. The lawsuit purports to include persons who acquired Mirant securities between

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September 26, 2000 and September 5, 2002.

     In July 2003, the court dismissed all claims based on Mirant’s alleged improper energy trading and marketing activities involving the California energy market. The remaining claims do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but seek to impose liability on Southern Company based on allegations that Southern Company was a “control person” as to Mirant prior to the spin-off date. Southern Company filed an answer to the consolidated amended class action complaint in September 2003. Plaintiffs have also filed a motion for class certification.

     During Mirant’s Chapter 11 proceeding, the securities litigation was stayed, with the exception of limited discovery. Since Mirant’s plan of reorganization has become effective, the stay has been lifted, and activity in this case is expected to resume.

     Under certain circumstances, Southern Company will be obligated under its Bylaws to indemnify the four current and/or former Southern Company officers who served as directors of Mirant at the time of its initial public offering through the date of the spin-off and who are also named as defendants in this lawsuit. The final outcome of this matter cannot now be determined.

Southern Company Employee Savings Plan Litigation

In June 2004, an employee of a Southern Company subsidiary filed a complaint, which was amended in December 2004 and November 2005 in the U.S. District Court for the Northern District of Georgia on behalf of a purported class of participants in or beneficiaries of The Southern Company Employee Savings Plan (Plan) at any time since April 2, 2001 and whose Plan accounts included investments in Mirant common stock. The complaint asserts claims under ERISA against defendants Southern Company, SCS, the Employee Savings Plan Committee, the Pension Fund Investment Review Committee, individual members of such committees, and the SCS Board of Directors during the putative class period. The plaintiff alleges that the various defendants had certain fiduciary duties under ERISA regarding the Mirant shares distributed to Southern Company shareholders in the spin-off and held in the Mirant Stock Fund in the Plan. The plaintiff alleges that the various defendants breached purported fiduciary duties by, among other things, failing to adequately determine whether Mirant stock was appropriate to hold in the Plan and failing to adequately inform Plan participants that Mirant stock was not an appropriate investment for their retirement assets based on Mirant’s alleged improper energy trading and accounting practices, mismanagement, and business conditions. The plaintiff also alleges that certain defendants failed to monitor Plan fiduciaries and that certain defendants had conflicting interests regarding Mirant, which prevented them from acting solely in the interests of Plan participants and beneficiaries. The plaintiff seeks class-wide equitable relief and an unspecified amount of monetary damages.

     On October 4, 2005, the court dismissed the plaintiff’s claims for certain types of equitable relief, but allowed the remainder of the ERISA claims to proceed. The defendants filed answers to the second amended complaint in January 2006, and filed motions for summary judgment and to stay discovery in February 2006. The ultimate outcome of this matter cannot now be determined.

Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues

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associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.

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

Plant Wansley Environmental Litigation

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of Georgia Power in part and the plaintiffs in part. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial which will address civil penalties and possible injunctive relief requested by the plaintiffs.

     The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Environmental Remediation

Georgia Power has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act. In 1995, the EPA designated Georgia Power and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia, that is listed on the federal National Priorities List. As of December 31, 2005, Georgia Power had recorded approximately $6 million in cumulative expenses associated with its agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. Additional claims for recovery of natural resource damages at the site are anticipated. Georgia Power has also recognized $36 million in cumulative expenses through December 31, 2005 for the assessment and anticipated cleanup of other sites on the Georgia Hazardous Sites Inventory.

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

FERC Matters

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates at market-based prices. The retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate

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transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $16 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the retail operating companies and Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $31 million, of which $11 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund a total of $19 million previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. Southern Company has also received similar requests from

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other entities totaling approximately $14 million. Southern Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on Southern Company and the final results of these matters cannot be determined at this time.

Race Discrimination Litigation

In July 2000, a lawsuit alleging race discrimination was filed by three Georgia Power employees against Georgia Power, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the U.S. District Court for the Northern District of Georgia and amended to add four more plaintiffs. The lawsuit also raised claims on behalf of a purported class. The plaintiffs sought compensatory and punitive damages in an unspecified amount, as well as injunctive relief.

     Following various court decisions in favor of the defendants and subsequent appeals by the plaintiffs, on July 13, 2005, the plaintiffs filed a petition for writ of certiorari to the U.S. Supreme Court. On October 17, 2005, the petition was denied. This matter is now concluded.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and its subsidiaries believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.

     In November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over Gulf Power rights of way located on the landowners’ property. Subsequently, the plaintiffs sought to amend their complaint and asked the court to enter a final declaratory judgment and to enter an order enjoining Gulf Power from allowing expanded general telecommunications use of the fiber optic cables that are the subject of this litigation. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against Gulf Power on their respective motions for partial summary judgment. In that same order, the trial court also denied Gulf Power’s motion to dismiss certain claims. The court’s ruling allowed for an immediate appeal to the Florida First District Court of Appeal, which Gulf Power filed on December 20, 2005. If the appeal is not successful, damages will be decided at a future trial.

     In January 2005, the Superior Court of Decatur County, Georgia, granted partial summary judgment in another such lawsuit brought by landowners against Georgia Power on the plaintiffs’ declaratory judgment claim that the easements do not permit general telecommunications use. The court also dismissed Southern Telecom from this case. The question of damages and other liability or remedies issues with respect to these actions, if any, will be decided at future trials. Georgia Power appealed this ruling to the Georgia Court of Appeals. The Georgia Court of Appeals reversed, in part, the court’s order and remanded the case to the trial court for the determination of further issues. After the Court of Appeals’ decision, the plaintiffs filed a motion for reconsideration, which was denied, and a petition for certiorari to the Georgia Supreme Court, which is currently pending. In the event of an adverse verdict in either case, Gulf Power or Georgia Power, as applicable, could appeal the issues of both liability and damages or other relief granted.

     To date, Mississippi Power has entered into agreements with plaintiffs in approximately 90 percent of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Mississippi Power’s financial statements.

     In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power,

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Savannah Electric, and Southern Telecom, were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Income Tax Matters

Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years through 2001. Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. The IRS proposed to disallow the tax losses for one of these leases (a lease-in-lease-out, or LILO) in connection with its audit of 1996 through 2001. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS which is subject to final approval. Under current accounting rules, the settlement of this transaction will have no material impact on Southern Company’s financial statements

     In connection with its audit of 2000 and 2001, the IRS also challenged Southern Company’s deductions related to three other international lease (sale-in-lease-out, or SILO) transactions. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company would be subject to additional interest charges of up to $34 million. The IRS has also proposed a penalty of approximately $16 million. Southern Company believes these transactions are valid leases for U.S. tax purposes, the related deductions are allowable, and the assessment of a penalty is inappropriate. Southern Company is continuing to pursue resolution of these matters with the IRS and expects to litigate the issue if necessary. Although the payment of the tax liability, exclusive of interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Through December 31, 2005, Southern Company has claimed $241 million in tax benefits related to these SILO transactions challenged by the IRS. See Note 1 under “Leveraged Leases” for additional information.

Alabama Power Retail Regulatory Matters

Alabama Power operates under a Rate Stabilization and Equalization plan (Rate RSE) approved by the Alabama PSC. Rate RSE provides for periodic annual adjustments based upon Alabama Power’s earned return on end-of-period retail common equity; however, in October 2005, Alabama Power and the Alabama PSC agreed to a moratorium on any rate increase under Rate RSE until January 2007. In October 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates will remain unchanged if the return on equity (ROE) is between 13 percent and 14.5 percent. If Alabama Power’s actual retail ROE is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006. The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.

     The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the placing of new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP).

     To recover certificated purchased power costs under Rate CNP, increases of 2.6 percent or $79 million annually and 0.8 percent or $25 million annually were effective July 2003 and June 2004,

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respectively. In April 2005, an annual true-up adjustment to Rate CNP decreased retail rates by approximately 0.5 percent or $18.5 million annually.

     In October 2004, the Alabama PSC approved a request by Alabama Power to amend Rate CNP to also provide for the recovery of retail costs associated with environmental laws and regulations, effective in January 2005. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 1 percent in both January 2005 and 2006.

     Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In December 2005, the Alabama PSC approved an increase that allows for the recovery of approximately $227 million in existing under recovered fuel costs over a two-year period. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet.

Georgia Power Retail Regulatory Matters

In December 2004, the Georgia PSC approved a three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan) for Georgia Power. Under the terms of the 2004 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees were increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. In 2005, Georgia Power recorded $5.3 million in revenue subject to refund related to earnings in excess of a 12.25 percent retail ROE.

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

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

     On May 17, 2005, the Georgia PSC approved Georgia Power’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet.

     Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power will be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with a Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. In connection with the proposed merger, Georgia Power has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, Georgia Power and Savannah Electric will file a combined request in March 2006 to increase its fuel cost recovery rate.

     The case will seek approval of a fuel cost

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recovery rate based upon future fuel cost projections for the combined Georgia Power and Savannah Electric generating fleet as well as the under recovered balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all Georgia Power customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the merger will be paid by the appropriate customer groups. For additional information regarding the pending merger, see “Merger of Georgia Power and Savannah Electric” below.

     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. Georgia Power and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of these matters cannot now be determined.

Storm Damage Cost Recovery

Each retail operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution facilities and the cost of uninsured damages to its generation facilities and other property. Following Hurricanes Ivan, Dennis, and Katrina in September 2004, July 2005, and August 2005, respectively, each of the affected retail operating companies has been authorized by its respective state PSC to defer the portion of the storm restoration costs incurred that exceeded the balance in its storm damage reserve account. As of December 31, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $366 million, of which approximately $70 million and $296 million, respectively, is included in the condensed balance sheets herein under Other Current Assets and Other Regulatory Assets. Approximately $81 million of the deficit balances are being recovered through separate surcharges or rate riders approved by the Florida and Alabama PSCs, as discussed further below. The recovery of the remaining deferred costs is subject to the approval of the respective state PSC.

     Hurricane Ivan caused significant damage to the service areas of both Gulf Power and Alabama Power. In February and December 2005, Alabama Power requested and received Alabama PSC approval of accounting orders that allowed Alabama Power to immediately return certain regulatory liabilities to the retail customers. The orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effect of these orders had no impact on net income in 2005. In March 2005, the Florida PSC approved a Stipulation and Settlement among Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group. The agreement allows Gulf Power to recover approximately $51.7 million in storm damage costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. Gulf Power also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     Hurricanes Dennis and Katrina caused significant damage within Southern Company’s service area, including portions of the service areas of Alabama Power and Gulf Power and all of Mississippi Power’s service area. Hurricane Dennis and Katrina restoration costs are currently estimated to total approximately $506 million, of which approximately $287 million relates to operation and maintenance expenditures. Approximately $60 million of these costs is expected to be covered through external insurance. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 Mississippi Power customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs or associated cost estimates. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.

     In December 2005, the Alabama PSC approved Alabama Power’s request for a separate rate rider to recover its $51 million of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish the reserve to a target balance of $75 million over a five-year period.

     Prior to Hurricane Katrina, Mississippi Power had a balance of approximately $3 million in its property reserve. In October 2005, the Mississippi PSC issued an Interim Accounting Order requiring Mississippi Power to recognize a regulatory asset in an amount

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equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. Through December 31, 2005, these incremental costs totaled $210 million, net of insurance proceeds of $68 million. These costs include approximately $133 million of operation and maintenance expenditures and approximately $49 million of capital additions, of which approximately $100 million are reflected as investing activities for purposes of the statement of cash flows. In December 2005, Mississippi Power filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. Mississippi Power is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to federal grant assistance and proposed state legislation to allow securitized financing. Also in December 2005, Mississippi Power submitted its annual Performance Evaluation Plan (PEP) filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, Mississippi Power has requested that the Mississippi PSC approve a temporary change to allow them to exceed this cap as a result of the ongoing effects of Hurricane Katrina. Mississippi Power has requested a 5 percent or $32 million retail base rate increase to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.

     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, Gulf Power filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over 8 years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve Gulf Power’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish Gulf Power’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since Gulf Power will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on net income, but would increase cash flow.

Plant Franklin Construction Project

Southern Power completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. As of December 31, 2005, Southern Power’s investment in Unit 3 of Plant Franklin was $172 million. The final outcome of this matter cannot now be determined.

Southern Company Gas Sale

On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary, including natural gas inventory, accounts receivable, and customer list, to Gas South, LLC, an affiliate of Cobb Electric Membership Corporation. Southern Company Gas’ sale of such assets was pursuant to a Purchase and Sale Agreement dated November 18, 2005 between Southern Company Gas and Gas South, for an aggregate purchase price of approximately $127 million, subject to certain adjustments. This sale will have no material impact on Southern Company’s net income for the quarter ending March 31, 2006. As a result of the sale, Southern Company’s financial statements and related information reflect Southern Company Gas as discontinued operations.

Merger of Georgia Power and Savannah Electric

On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement, under which Savannah Electric will merge into Georgia Power, with Georgia Power continuing as the surviving corporation. At the effective date of the merger, each share of Georgia Power common stock will remain issued and outstanding; the issued and outstanding shares of Savannah Electric common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of Georgia Power common stock; and each share of Savannah Electric preferred stock issued and outstanding immediately prior to the merger will be converted into the right to receive one share of a new series of Georgia Power Class A Preferred Stock. The merger must be approved by the preferred shareholders of Savannah Electric, and is subject to the receipt of regulatory approvals from the FERC, Georgia PSC, and Federal Communications Commission. Pending regulatory approvals, the merger is expected to occur by July

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2006. The merger is not expected to have any material impact on Southern Company’s financial statements.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Alabama Electric Cooperative, Inc.

     Georgia Power owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia, the city of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Florida Power Corporation for a combustion turbine unit at Intercession City, Florida.

     Southern Power owns an undivided interest in Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.

     At December 31, 2005, Alabama Power’s, Georgia Power’s, and Southern Power’s ownership and investment (exclusive of nuclear fuel) in jointly owned facilities with the above entities were as follows:

	Jointly Owned Facilities
	Percent			Amount of		Accumulated
	Ownership			Investment		Depreciation
				(in millions)
Plant Vogtle (nuclear)		45.7	%	$	3,311	$	1,809
Plant Hatch (nuclear)		50.1			935		492
Plant Miller (coal) Units 1 and 2		91.8			940		374
Plant Scherer (coal) Units 1 and 2		8.4			115		56
Plant Wansley (coal)		53.5			395		172
Rocky Mountain (pumped storage)		25.4			169		92
Intercession City (combustion turbine)		33.3			12		2
Plant Stanton (combined cycle) Unit A		65.0			156		10

     At December 31, 2005, the portion of total construction work in progress related to Plants Miller, Scherer, and Wansley was $4.4 million, $0.5 million, and $8.3 million, respectively, primarily for environmental projects.

     Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies’ proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income.

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

     Mirant was included in the consolidated federal tax return through April 2, 2001. In December 2004, the IRS concluded its audit for the tax years 2000 and 2001, and Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements, Mirant agreed to indemnify Southern Company for subsequent assessment of any additional taxes related to its transactions prior to the spin off. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor. For additional information, see Note 3 under “Mirant Matters — Mirant Bankruptcy.”

     At December 31, 2005, the tax-related regulatory assets and liabilities were $937 million and $313 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

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     Details of income tax provisions are as follows:

	2005		2004		2003
	(in millions)
Total provision for income taxes:
Federal —
Current	$	61	$	14	$	141
Deferred		419		482		393
		480		496		534
State —
Current		35		15		44
Deferred		80		76		34
		115		91		78
Total	$	595	$	587	$	612

     Net cash payments for income taxes in 2005, 2004, and 2003 were $100 million, $78 million, and $189 million, respectively.

     The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	4,613		$	4,290
Property basis differences		1,008			1,009
Leveraged lease basis differences		519			447
Employee benefit obligations		333			307
Under recovered fuel clause		528			210
Premium on reacquired debt		126			132
Storm reserve		68			47
Other		155			133
Total		7,350			6,575
Deferred tax assets:
Federal effect of state deferred taxes		263			243
State effect of federal deferred taxes		88			111
Employee benefit obligations		210			177
Other property basis differences		148			157
Deferred costs		126			105
Unbilled revenue		58			61
Other comprehensive losses		96			94
Alternative minimum tax carryforward		202			106
Other		260			233
Total		1,451			1,287
Total deferred tax liabilities, net		5,899			5,288
Portion included in prepaid expenses (accrued income taxes), net		(180	)		(57	)
Deferred state tax assets		17			12
Accumulated deferred income taxes in the balance sheets	$	5,736		$	5,243

     The alternative minimum tax credits do not expire.

     At December 31, 2005, Southern Company also had available State of Georgia net operating loss carryforward deductions totaling $1.0 billion, which could result in net state income tax benefits of $59 million, if utilized. These deductions will expire between 2006 and 2021. During 2005, Southern Company utilized $11 million in available net operating losses, which resulted in a $0.7 million state income tax benefit. Beginning in 2002, the State of Georgia allowed the filing of a combined return, which should substantially reduce any additional net operating loss carryforwards.

     In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $25 million in 2005, $27 million in 2004, and $29 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

     The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred dividends of subsidiaries, as a result of the following:

	2005			2004			2003
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		3.4			2.8			2.4
Synthetic fuel tax credits		(8.0	)		(8.5	)		(5.7	)
Employee stock plans dividend deduction		(1.5	)		(1.5	)		(1.5	)
Non-deductible book depreciation		1.1			1.1			1.1
Difference in prior years’ deferred and current tax rate		(1.8	)		(0.7	)		(0.7	)
Other		(1.4	)		(0.9	)		(1.5	)
Effective income tax rate		26.8	%		27.3	%		29.1	%

6. FINANCING

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

Southern Company and the retail operating companies have each formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Southern Company and the retail operating companies through the issuance of junior

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subordinated notes totaling $2.0 billion, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trusts (including Securities Due Within One Year). Southern Company and the retail operating companies each consider that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2005, preferred securities of $1.9 billion were outstanding. Southern Company guarantees $574 million of notes related to these securities issued on its behalf. Subsequent to year-end, this amount has been reduced to $502 million through the redemption of outstanding securities. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Securities Due Within One Year

A summary of scheduled maturities and redemptions of securities due within one year at December 31 is as follows:

	2005		2004
	(in millions)
Capitalized leases	$	13	$	12
First mortgage bonds		45		—
Pollution control bonds		12		—
Senior notes		697		675
Long-term debt payable to affiliated trusts		72		—
Other long-term debt		47		296
Preferred stock		15		—
Total	$	901	$	983

     Debt and preferred stock redemptions, and/or serial maturities through 2010 applicable to total long-term debt are as follows: $901 million in 2006; $1.5 billion in 2007; $486 million in 2008; $591 million in 2009, and $243 million in 2010.

Assets Subject to Lien

Each of Southern Company’s subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. Alabama Power, Gulf Power, and Savannah Electric have mortgages that secure first mortgage bonds they have issued and constitute a direct first lien on substantially all of their respective fixed property and franchises. Mississippi Power discharged its mortgage in June 2005, and the lien was removed. The Georgia Power lien was removed in 2002. The remaining outstanding first mortgage bonds of Gulf Power and Savannah Electric mature in 2006. There are no agreements or other arrangements among the subsidiary companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.

Bank Credit Arrangements

At the beginning of 2006, unused credit arrangements with banks totaled $3.3 billion, of which $810 million expires during 2006 and $2.5 billion expires during 2007 and beyond. The following table outlines the credit arrangements by company:

					Expires
							2007 &
Company	Total		Unused		2006		beyond
	(in millions)
Alabama Power	$	878	$	878	$	428	$	450
Georgia Power		780		778		70		710
Gulf Power		121		121		121		—
Mississippi Power		326		276		101		225
Savannah Electric		80		80		60		20
Southern Company		750		750		—		750
Southern Power		400		399		—		400
Other		30		30		30		—
Total	$	3,365	$	3,312	$	810	$	2,555

     Approximately $228 million of the credit facilities expiring in 2006 allow the execution of term loans for an additional two-year period, and $311 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates.

     All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are one-eighth of 1 percent or less for Southern Company, the retail operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal. Included in the total $3.3 billion of unused credit arrangements is $2.3 billion of syndicated credit arrangements that require the payment of agent fees.

     Most of the credit arrangements with banks have covenants that limit debt levels to 65 percent of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts. At December 31, 2005, Southern Company, Southern Power, and the retail operating companies were each in

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compliance with their respective debt limit covenants.

     In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. The cross default provisions are restricted only to the indebtedness, including any guarantee obligations, of the company that has such credit arrangements. Southern Company and its subsidiaries are currently in compliance with all such covenants. Borrowings under certain retail operating companies’ unused credit arrangements totaling $10 million would be prohibited if the borrower experiences a material adverse change, as defined in such arrangements.

     A portion of the $3.3 billion unused credit with banks is allocated to provide liquidity support to the retail operating companies’ variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2005 was $720 million.

     Southern Company, the retail operating companies, and Southern Power borrow primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the retail operating companies may also borrow through various other arrangements with banks and extendible commercial note programs. The amount of commercial paper outstanding and included in notes payable in the balance sheets at December 31, 2005 and December 31, 2004 was $944 million and $377 million, respectively.

     During 2005, the peak amount outstanding for short-term debt was $1.26 billion, and the average amount outstanding was $738 million. The average annual interest rate on short-term debt was 3.5 percent for 2005 and 1.3 percent for 2004 and 2003.

Financial Instruments

The retail operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the retail operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. Each of the retail operating companies has implemented fuel-hedging programs at the instruction of their respective state PSCs. Together with Southern Power, the retail operating companies may enter into hedges of forward electricity sales. In addition, Southern Company Gas had gas-hedging programs to substantially mitigate its exposure to price volatility for its gas purchases.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in millions)
Regulatory liabilities, net	$	103.4
Other comprehensive income		(0.3	)
Net income		(2.6	)
Total fair value	$	100.5

     The fair value gains or losses for hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. For Southern Power, the fair value gains or losses for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. For 2005, 2004, and 2003, approximately $7 million, $(3) million, and $22 million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to fuel expense. For the year 2006, no material amounts are expected to be reclassified from other comprehensive income to fuel expense. There was no significant ineffectiveness recorded in earnings for any period presented. Southern Company has energy-related hedges in place up to and including 2008.

     Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to changes in interest rates. Derivatives related to fixed-rate securities are accounted for as fair value hedges. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

     At December 31, 2005, Southern Company had $2.8 billion notional amount of interest rate swaps and options outstanding with net fair value gains of $31.7 million as follows:

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Southern Company and Subsidiary Companies 2005 Annual Report

Fair Value Hedges

		Variable			Fair
		Rate	Notional		Value
Company	Maturity	Paid	Amount		Gain
			(in millions)
Southern Company
	2007	6-month	$	400	$	3.0
		LIBOR - 0.10%

Cash Flow Hedges

		Weighted Average					Fair
		Fixed					Value
		Rate			Notional		Gain/
Company	Maturity	Paid			Amount		(Loss)
					(in millions)
Alabama Power
	2007		2.01	%*	$	536	$	7.3
	2006		1.89	%		195		2.5
	2016		4.82	%		300		3.0
	2016		4.42	%		300		12.5
Georgia Power
	2006-2007		2.09-3.85	%**		400		1.2
	2037		4.58-5.75	%***		300		(1.1	)
	2007		2.67	%		300		2.4
Savannah Electric
	2007		2.50	%*		14		0.3
	2016		4.69	%		30		0.6

*	Hedged using the Bond Market Association Municipal Swap Index.
**	Series of interest rate caps and collars (showing the lowest floor and highest cap) with variable rates based on one-month LIBOR.
***	Interest rate collar.

     For fair value hedges where the hedged item is an asset, liability, or firm commitment, the changes in the fair value of the hedging derivatives are recorded in earnings and are offset by the changes in the fair value of the hedged item.

     The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2005, 2004, and 2003, the Company incurred losses of $19 million, $7 million, and $116 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. For 2005, 2004, and 2003, approximately $10 million, $23 million, and $26 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2006, pre-tax losses of approximately $2 million are expected to be reclassified from other comprehensive income to interest expense.

7. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently estimated to total $2.8 billion in 2006, $3.6 billion in 2007, and $3.1 billion in 2008. These amounts include $63 million, $39 million, and $23 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included herein under “Fuel and Purchased Power Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the ongoing construction program, which includes capital improvements to generation, transmission, and distribution facilities, including those to meet environmental standards.

Long-Term Service Agreements

The retail operating companies and Southern Power have entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned by the subsidiaries. The LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

     In general, except for Southern Power’s Plant Dahlberg, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg agreement is in effect through the first major inspection of each unit. Scheduled payments to GE are made at various intervals based on actual

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operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.8 billion over the remaining life of the agreements, which may range up to 30 years. However, the LTSAs contain various cancellation provisions at the option of the purchasers.

     Georgia Power has also entered into an LTSA with GE through 2014 for $14.9 million worth of neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $13.1 million. The contract contains cancellation provisions at the option of Georgia Power.

     Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed by GE is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2005 were as follows:

	Commitments
	Natural				Nuclear		Purchased
	Gas		Coal		Fuel		Power
	(in millions)
2006	$	1,495	$	3,129	$	63	$	175
2007		805		2,509		39		176
2008		481		1,450		23		180
2009		371		864		14		162
2010		369		694		20		143
2011 and thereafter		3,046		364		89		541
Total	$	6,567	$	9,010	$	248	$	1,377

     Additional commitments for fuel will be required to supply Southern Company’s future needs.

Operating Leases

In May 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. In 2003, approximately $11 million in lease termination costs were also included in operation expenses. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50 percent of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The initial lease term ends in 2011, and the lease includes a purchase and renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4 percent of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, Mississippi Power may elect to renew for 10 years. If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17 percent of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power’s option, it may either exercise its purchase option or the facility can be sold to a third party.

     The lease provides for a residual value guarantee, approximately 73 percent of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the asset. A liability of approximately $11 million for the fair market value of this residual value guarantee is included in the balance sheet as of December 31, 2005.

     Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $150 million, $156 million, and $172 million for 2005, 2004, and 2003, respectively. Southern Company includes any step

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. At December 31, 2005, estimated minimum lease payments for noncancelable operating leases were as follows:

	Minimum Lease Payments
	Plant		Rail
	Daniel		Cars		Other		Total
			(in millions)
2006	$	29	$	42	$	52	$	123
2007		29		34		46		109
2008		29		31		36		96
2009		29		24		30		83
2010		28		22		23		73
2011 and thereafter		28		84		147		259
Total	$	172	$	237	$	334	$	743

     For the retail operating companies, the rail car lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2006, 2009, and 2011, and the maximum obligations are $66 million, $20 million, and $68 million, respectively. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.

Guarantees

Prior to the spin-off, Southern Company made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant’s trading and marketing subsidiaries. The total notional amount of guarantees outstanding at December 31, 2005 is less than $20 million, all of which will expire by 2009.

     Southern Company has executed a keep-well agreement with a subsidiary of Southern Holdings to make capital contributions in the event of any shortfall in payments due under a participation agreement with an entity in which the subsidiary holds a 30 percent investment. The maximum aggregate amount of Southern Company’s liability under this keep-well agreement is $50 million.

     As discussed earlier in this Note under “Operating Leases,” Alabama Power, Georgia Power, and Mississippi Power have entered into certain residual value guarantees.

8. COMMON STOCK

Stock Issued

Southern Company raised $213 million (10 million shares) in 2005 and $124 million (7 million shares) in 2004 from the issuance of new common shares under the Company’s various stock plans.

Stock Repurchased

During 2005, in a program designed primarily to offset the issuances discussed above, Southern Company repurchased 10 million shares of common stock at a total cost of $352 million. The repurchase program was discontinued in early January 2006.

Shares Reserved

At December 31, 2005, a total of 64.9 million shares was reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option plan).

Stock Option Plan

Southern Company provides non-qualified stock options to a large segment of its employees ranging from line management to executives. As of December 31, 2005, 6,329 current and former employees participated in the stock option plan. The maximum number of shares of common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three
years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2003 to 2005 for the stock option plan is summarized below:

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

	Shares			Average
	Subject			Option Price
	To Option			Per Share
Balance at December 31, 2002		32,674,814			19.72
Options granted		7,165,190			27.98
Options canceled		(181,381	)		24.37
Options exercised		(5,725,336	)		16.56
Balance at December 31, 2003		33,933,287			21.97
Options granted		7,231,703			29.49
Options canceled		(72,794	)		26.85
Options exercised		(6,557,690	)		18.11
Balance at December 31, 2004		34,534,506			24.27
Options granted		6,969,083			32.71
Options canceled		(83,366	)		28.01
Options exercised		(10,072,868	)		21.17
Balance at December 31, 2005		31,347,355		$	27.13
Shares reserved for future grants:
At December 31, 2003		39,751,477
At December 31, 2004		32,583,523
At December 31, 2005		25,687,333
Options exercisable:
At December 31, 2003		18,874,426
At December 31, 2004		21,782,064
At December 31, 2005		18,535,238

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares (in thousands)		4,157		13,370		13,821
Average remaining life (in years)		4.2		5.9		8.2
Average exercise price	$	17.25	$	26.10	$	31.10
Exercisable:
Shares (in thousands)		4,157		11,465		2,914
Average exercise price	$	17.25	$	25.79	$	29.67

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to outstanding options under the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows:

	Average Common Stock Shares
	2005		2004		2003
		(in thousands)
As reported shares		743,927		738,879		726,702
Effect of options		4,600		4,197		5,202
Diluted shares		748,527		743,076		731,904

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2005, consolidated retained earnings included $4.5 billion of undistributed retained earnings of the subsidiaries. Of this amount, $68 million was restricted against the payment of cash dividends on common stock by Savannah Electric under terms of its bond indenture. Southern Power’s credit facility also contains potential limitations on the payment of common stock dividends; as of December 31, 2005, Southern Power was in compliance with all such requirements.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendment Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies’ nuclear power plants. The Act provides funds up to $10.76 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. A company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests, is $201 million and $203 million, respectively, per incident, but not more than an aggregate of $30 million per company to be paid for each incident in any one year.

     Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.

     Additionally, both companies have policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

     NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.

     Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $41 million and $48 million, respectively.

     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all “non-certified” terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.

     For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

     All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segment is the sale of electricity in the Southeast by the five retail operating companies and Southern Power. Net income and total assets for discontinued operations are included in the reconciling eliminations column. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in synthetic fuels and leveraged lease projects, telecommunications, and energy-related services. Southern Power’s revenues from sales to the retail operating companies were $557 million, $425 million, and $313 million in 2005, 2004, and 2003, respectively. In addition, see Note 1 under “Related Party Transactions” for information regarding revenues from services for synthetic fuel production that are included in the cost of fuel purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Business Segment

	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
								(in millions)
2005
Operating revenues	$	13,156	$	781	$	(659	)	$	13,278	$	393		$	(117	)	$	13,554
Depreciation and amortization		1,083		54		—			1,137		39			—			1,176
Interest income		30		2		—			32		5			(1	)		36
Interest expense		567		79		—			646		101			—			747
Income taxes		827		72		—			899		(304	)		—			595
Segment net income (loss)		1,398		115		—			1,513		80			(2	)		1,591
Total assets		36,335		2,303		(179	)		38,459		1,751			(333	)		39,877
Gross property additions		2,177		241		—			2,418		58			—			2,476

	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
								(in millions)
2004
Operating revenues	$	11,300	$	701	$	(536	)	$	11,465	$	375		$	(111	)	$	11,729
Depreciation and amortization		857		51		—			908		41			—			949
Interest income		24		1		—			25		4			(2	)		27
Interest expense		518		66		—			584		83			—			667
Income taxes		802		73		—			875		(290	)		—			585
Segment net income (loss)		1,309		112		—			1,421		109			2			1,532
Total assets		33,517		2,067		(104	)		35,480		1,895			(420	)		36,955
Gross property additions		2,307		116		(415	)		2,008		91			—			2,099

	Electric Utilities
	Retail
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
								(in millions)
2003
Operating revenues	$	10,502	$	682	$	(437	)	$	10,747	$	357		$	(86	)	$	11,018
Depreciation and amortization		933		39		—			972		49			1			1,022
Interest income		33		—		—			33		6			(3	)		36
Interest expense		542		32		—			574		108			(4	)		678
Income taxes		760		85		—			845		(228	)		1			618
Segment net income (loss)		1,269		155		—			1,424		59			(9	)		1,474
Total assets		31,503		2,409		(122	)		33,790		1,574			(189	)		35,175
Gross property additions		1,636		344		—			1,980		34			—			2,014

Products and Services

	Electric Utilities Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2005	$	11,165	$	1,667	$	446	$	13,278
2004		9,732		1,341		392		11,465
2003		8,875		1,358		514		10,747

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NOTES (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2005 and 2004 — including discontinued operations for net income and earnings per share — are as follows:

							Per Common Share (Note)
	Operating		Operating		Consolidated		Basic						Price Range
Quarter Ended	Revenues		Income		Net Income		Earnings		Dividends		High			Low
			(in millions)
March 2005	$	2,787	$	560	$	323	$	0.43	$	0.3575	$	34.08		$	31.25
June 2005		3,120		721		387		0.52		0.3725		34.91			31.78
September 2005		4,358		1,277		722		0.97		0.3725		36.16			33.47
December 2005		3,289		404		159		0.21		0.3725		36.07			33.28
March 2004	$	2,651	$	615	$	331	$	0.45	$	0.3500	$	30.87		$	29.10
June 2004		2,984		697		352		0.48		0.3500		30.59			27.86
September 2004		3,424		1,120		645		0.87		0.3575		30.65			28.86
December 2004		2,670		389		204		0.28		0.3575		33.92			29.95

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

II-76

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2001 through 2005
Southern Company and Subsidiary Companies 2005 Annual Report

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

II-77

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2001 through 2005
Southern Company and Subsidiary Companies 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in millions):
Residential	$	4,376	$	3,848	$	3,565	$	3,556	$	3,247
Commercial		3,904		3,346		3,075		3,007		2,966
Industrial		2,785		2,446		2,146		2,078		2,144
Other		100		92		89		87		83
Total retail		11,165		9,732		8,875		8,728		8,440
Sales for resale		1,667		1,341		1,358		1,168		1,174
Total revenues from sales of electricity		12,832		11,073		10,233		9,896		9,614
Other revenues		722		656		785		551		541
Total	$	13,554	$	11,729	$	11,018	$	10,447	$	10,155
Kilowatt-Hour Sales (in millions):
Residential		51,082		49,702		47,833		48,784		44,538
Commercial		51,857		50,037		48,372		48,250		46,939
Industrial		55,141		56,399		54,415		53,851		52,891
Other		996		1,005		998		1,000		977
Total retail		159,076		157,143		151,618		151,885		145,345
Sales for resale		37,801		35,239		40,520		32,551		30,768
Total		196,877		192,382		192,138		184,436		176,113
Average Revenue Per Kilowatt-Hour (cents):
Residential		8.57		7.74		7.45		7.29		7.29
Commercial		7.53		6.69		6.36		6.23		6.32
Industrial		5.05		4.34		3.94		3.86		4.05
Total retail		7.02		6.19		5.85		5.75		5.81
Sales for resale		4.41		3.81		3.35		3.59		3.82
Total sales		6.52		5.76		5.33		5.37		5.46
Average Annual Kilowatt-Hour
Use Per Residential Customer		14,084		13,879		13,562		14,036		13,014
Average Annual Revenue
Per Residential Customer	$	1,207	$	1,074	$	1,011	$	1,023	$	949
Plant Nameplate Capacity
Ratings (year-end) (megawatts)		40,502		38,622		38,679		36,353		34,579
Maximum Peak-Hour Demand (megawatts):
Winter		30,384		28,467		31,318		25,939		26,272
Summer		35,050		34,414		32,949		32,355		29,700
System Reserve Margin (at peak) (percent)		14.4		20.2		21.4		13.3		19.3
Annual Load Factor (percent)		60.2		61.4		62.0		51.1		62.0
Plant Availability (percent):
Fossil-steam		89.0		88.5		87.7		84.8		88.1
Nuclear		90.5		92.8		94.4		90.3		90.8
Source of Energy Supply (percent):
Coal		67.0		64.6		66.4		65.7		67.5
Nuclear		13.9		14.4		14.8		14.7		15.2
Hydro		3.1		2.9		3.8		2.6		2.6
Oil and gas		10.9		10.9		8.8		11.4		8.4
Purchased power		5.1		7.2		6.2		5.6		6.3
Total		100.0		100.0		100.0		100.0		100.0

II-78

ALABAMA POWER COMPANY

FINANCIAL SECTION

II-79

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Alabama Power Company

We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements (pages II-100 to II-127) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Birmingham, Alabama
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2005 Annual Report

OVERVIEW

Business Activities

Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast.

     Many factors affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and restoration following major storms.

     On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the Company’s service territory including the Company’s distribution and transmission facilities. Approximately 241,000 and 637,000, respectively, of the Company’s 1.4 million customers were without electrical service immediately after Hurricanes Dennis and Katrina.

     In 2005, the Company successfully completed a retail rate proceeding with the Alabama Public Service Commission (PSC) to recover the costs associated with these storms and to replenish the Company’s natural disaster reserve. In other actions, the Alabama PSC also approved a higher fuel recovery rate and amended the Company’s Rate Stabilization and Equalization Plan (Rate RSE) to use forward-looking test periods. These regulatory actions are expected to assist the Company’s continued focus on providing reliable electrical service to customers while maintaining a stable financial position.

Key Performance Indicators

In striving to maximize shareholder value while providing cost effective energy to customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects. The 2005 Peak Season EFOR exceeded target levels primarily due to equipment malfunctions at Plant Barry units 5 and 6, which resulted in unexpected outages. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2005 performance was above target on these reliability measures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2005 results compared with its targets for each of these indicators are reflected in the following chart.

Key	2005	2005
Performance Indicator	Target Performance	Actual Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season EFOR	2.75% or less	3.83%
Net Income	$501 million	$508 million

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the focus that management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

Earnings

The Company’s financial performance remained strong in 2005 despite the challenges of major hurricane restorations and rising fuel costs. The Company’s net income after dividends on preferred stock of $508 million in 2005 increased $27 million (5.6 percent) over the prior year. This improvement is primarily due to retail and wholesale revenue growth, increases in transmission revenues, partially offset by higher non-fuel operating expenses.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

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

     The Company’s 2003 net income after dividends on preferred stock was $473 million, representing a $12 million (2.5 percent) increase from the prior year. This improvement was due primarily to higher retail sales, higher sales for resale, increases in customer fees revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.

     The ROE for 2005 was 13.72 percent compared to 13.53 percent in 2004 and 13.75 percent in 2003.

RESULTS OF OPERATIONS

A condensed income statement is as follows:

				Increase (Decrease)
	Amount			From Prior Year
	2005			2005			2004		2003
	(in millions)
Operating revenues	$	4,648		$	412		$	276	$	250
Fuel		1,457			271			119		98
Purchased power		457			44			98		66
Other operation and maintenance		1,044			97			26		67
Depreciation and amortization		427			1			13		15
Taxes other than income taxes		249			6			14		11
Total operating expenses		3,634			419			270		257
Operating income		1,014			(7	)		6		(7	)
Total other income and (expense)		(197	)		6			30		20
Income taxes		285			(29	)		23		(2	)
Net income		532			28			13		15
Dividends on preferred stock		24			1			5		3
Net income after dividends on preferred stock	$	508		$	27		$	8	$	12

Revenues

Operating revenues for 2005 were $4.6 billion, reflecting a $412 million increase from 2004. The following table summarizes the principal factors that have affected operating revenues for the past three years:

	Amount
	2005			2004			2003
	(in millions)
Retail — prior year	$	3,293		$	3,051		$	2,951
Change in -
Base rates		35			41			51
Sales growth		50			48			68
Weather		18			12			(61	)
Fuel cost recovery and other		225			141			42
Retail — current year		3,621			3,293			3,051
Sales for resale —
Non-affiliates		551			484			488
Affiliates		289			308			277
Total sales for resale		840			792			765
Other operating revenues		187			151			144
Total operating revenues	$	4,648		$	4,236		$	3,960
Percent change		9.7	%		7.0	%		6.7	%

     Retail revenues in 2005 were $3.6 billion. Revenues increased $328 million (10.0 percent) in 2005, $242 million (7.9 percent) in 2004, and $100 million (3.4 percent) in 2003. These increases were primarily due to increased fuel revenue and retail base rate increases of 0.5 percent in April 2005, 1.0 percent in January 2005, 0.8 percent in July 2004, and 2.6 percent in July 2003. See FUTURE EARNINGS POTENTIAL – “PSC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

     Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.

     Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida utilities. Revenues from unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows:

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report

	2005		2004		2003
	(in thousands)
Unit power -
Capacity	$	147,609	$	134,615	$	130,022
Energy		169,080		146,809		145,342
Total	$	316,689	$	281,424	$	275,364

     No significant declines in the amount of capacity are scheduled until the termination of the contracts in 2010.

     Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. Revenues associated with other power sales to non-affiliates were as follows:

	2005		2004		2003
	(in thousands)
Other power sales -
Capacity and other	$	116,181	$	90,673	$	96,263
Variable cost of energy		118,537		111,742		115,829
Total	$	234,718	$	202,415	$	212,092

     Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC) as approved by the Federal Energy Regulatory Commission (FERC). In 2005, sales for resale revenues decreased $19.4 million primarily due to a 20.7 percent decrease in kilowatt-hour sales to affiliates as a result of a decrease in the availability of the Company’s generating resources due to an increase in customer demand within the Company’s service territory. Sales for resale revenues increased $31.1 million in 2004 due to increases in fuel-related expenses. Sales for resale revenues increased $89.1 million in 2003 due to increased capacity payments received from affiliates. Excluding the capacity revenues, these transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company’s energy cost recovery clause.

     Other operating revenues in 2005 increased $35.0 million (23.2 percent) from 2004 due to an increase of $20 million in revenues from gas-fueled co-generation steam facilities primarily as a result of higher gas prices, and $7.7 million increase in transmission revenues and a $3.9 million increase from rent from associated companies primarily related to leased transmission facilities.

     Other operating revenues in 2004 increased $7.0 million (4.9 percent) from 2003 due to an increase of $7.7 million in revenues from gas-fueled co-generation steam facilities — primarily as a result of higher gas prices – and a $2.4 million increase in revenues from rent from electric property offset by a $2.0 million decrease in transmission revenues.

     Other operating revenues in 2003 increased $47 million (48.6 percent) from 2002 due to an increase of $19.4 million in revenues from gas-fueled co-generation steam facilities — primarily as a result of higher gas prices — and a $14.8 million increase in revenues from Alabama PSC approved fees charged to customers for connection, reconnection, and collection when compared to the same period in 2002.

     Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.

Energy Sales

Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2005 and the percent change by year were as follows:

	KWH		Percent Change
	2005		2005			2004			2003
	(millions)
Residential		18,074		4.1	%		2.4	%		(2.5	)%
Commercial		14,062		1.7			2.8			0.7
Industrial		23,350		2.2			5.8			2.3
Other		198		0.2			(2.4	)		(1.1	)
Total retail		55,684		2.7			3.9			0.3
Sales for resale —
Non-affiliates		15,443		(0.3	)		(9.4	)		9.9
Affiliates		5,735		(20.7	)		(23.2	)		6.5
Total		76,862		(0.1	)		(2.2	)		2.9

     Retail energy sales in 2005 were 2.7 percent higher than 2004 despite interruptions during Hurricanes Dennis and Katrina. Energy sales in the residential sector led the growth with a 4.1 percent increase in 2005 due primarily to increased demand. Commercial sales increased 1.7 percent in 2005 primarily due to continued customer growth. Industrial sales increased 2.2 percent during the

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

year with chemical, primary metals and automotive leading the growth in industrial energy consumption. In addition, the paper sector chose to purchase rather than self-generate which contributed to increased sales.

     Energy sales in the residential sector grew by 2.4 percent in 2004 primarily due to continued customer growth and a return to normal summer temperatures. Commercial sales increased 2.8 percent in 2004 primarily due to continued customer growth. Industrial sales rebounded 5.8 percent during the year with primary metals, chemical, and paper sectors leading the growth.

     In 2003, residential energy sales experienced a 2.5 percent decrease over the prior year and total retail energy sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the previous year. Although retail sales to industrial customers increased 2.3 percent in 2003 and 3.1 percent in 2002, overall sales to industrial customers remained depressed due to the effect of sluggish economic conditions.

     Assuming normal weather, sales to retail customers are projected to grow approximately 1.3 percent annually on average during 2006 through 2010.

Total Operating Expenses

In 2005 total operating expenses increased $419 million (13.0 percent) to $3.6 billion. This change from 2004 includes an increase in fuel expense of $271 million (22.8 percent) related to higher natural gas and coal prices. In addition, purchased power expenses increased $45 million (10.8 percent) primarily due to a 17.9 percent increase in purchased power prices. Maintenance expenses increased $48 million primarily from transmission and distribution expense. These increases are mainly a result of the Alabama PSC accounting order to recognize the previously deferred costs of Hurricane Ivan storm damage restoration and to partially replenish a balance in the natural disaster reserve. See Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Cost Recovery” for additional information.

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

     The total operating expenses in 2003 were approximately $3.0 billion, an increase of $257 million (9.6 percent) over the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an increase in the average cost of natural gas and coal. In addition, purchased power expenses increased a total of $66 million, maintenance expense increased $30 million primarily related to transmission and distribution overhead lines, and depreciation and amortization expense increased $15 million.

Fuel and Purchased Power Expenses

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

	2005		2004		2003
Total generation
(billions of KWHs)		71		70		72
Sources of generation
(percent) —
Coal		67		65		64
Nuclear		19		19		19
Hydro		6		6		8
Gas		8		10		9
Average cost of fuel per net KWH generated (cents)		2.02		1.69		1.54
Average cost of purchased power per net KWH (cents)		6.49		4.79		3.61

     Fuel expense increased 22.8 percent in 2005 primarily due to an increase in the average cost of fuel as a result of a 26.5 percent increase in the average price of natural gas and an 18.5 percent increase in the average coal price. Fuel expense increased 11.1 percent in 2004 primarily due to a 30.5 percent increase in the average price of natural gas and a 3.1 percent increase in the average price of coal. Fuel expense increased 10.1 percent in 2003 due to a 58.3 percent increase in the average price of natural gas and a 2.2 percent increase in the average price of coal.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

     Purchased power consists of purchases from affiliates in the Southern Company electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand and the availability and variable production cost of generating resources at each company. Purchased power from non-affiliates increased $2.5 million (1.0 percent) in 2005. This was due to a 14.3 percent increase in purchased power prices over the previous year. In 2004, purchased power from non-affiliates increased $75 million (68 percent) due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices compared to 2003. In 2003, purchased power from non-affiliates increased $20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy purchased when compared to 2002.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses, including purchased power, are offset by fuel revenues through the Company’s energy cost recovery clause and generally have no effect on net income. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. See Future Earnings Potential — “PSC Matters – Retail Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.

Other Expenses

Depreciation and amortization expense increased 0.1 percent in 2005, 3.1 percent in 2004, and 3.6 percent in 2003. These increases reflect additions to property, plant, and equipment.

     Allowance for equity funds used during construction (AFUDC) increased $4.1 million (25.6 percent) and $3.5 million (28.2 percent) in 2005 and 2004, respectively, primarily due to increases in the amount of construction work in progress over the prior year. AFUDC also increased $1.4 million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate. See Note 1 to the financial statements under “AFUDC” for additional information.

     In 2005 interest expense, net of amounts capitalized increased $3.8 million to $197.4 million due to an increase in average debt outstanding during the year. This reversed the trend of the past two years when refinancing activities resulted in $20.7 million (9.7 percent) and $11.4 million (5.1 percent) decreases in 2004 and 2003, respectively.

Effects of Inflation

The Company is subject to rate regulation that is based on the recovery of costs. When historical costs are included, or when inflation exceeds projected costs used, in rate regulation, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been substantial. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in the State of Alabama and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the Company’s ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Northern District of Georgia granted the Company’s motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, the Company and the EPA are currently participating in mediation with respect to the EPA’s claims.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Alabama’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Environmental Statutes and Regulations

General

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act, and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $961 million in capital projects to comply with these requirements, with annual totals of $256 million, $177 million, and $100 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $2.2 billion, including $285 million, $426 million, and $406 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $745 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂ and NO_x emissions, maintain compliance with existing regulations, and to meet new requirements.

     Approximately $594 million of these expenditures related to reducing NO_x emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NO_x reduction rules. In 2004, the regional NO_x reduction rules were implemented for the northern two-thirds of Alabama. See Note 3 to the financial statements under “Retail Regulatory Matters” for information regarding the Company’s recovery of costs associated with environmental laws and regulations.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. The area within the Company’s service area that has been designated as nonattainment under the eight-hour ozone standard includes Jefferson and Shelby Counties, near Birmingham. State implementation plans, including new emission control regulations necessary to bring those areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NO_x emissions from power plants.

     In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment. The final outcome of this matter cannot now be determined.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within the Company’s service area, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO₂ and NO_x emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses SO₂ and NO_x emissions from power plants that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emissions allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.

     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

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Environmental Remediation

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change, and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 — 2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an

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adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. The Company has also received similar requests from other entities totaling approximately $7 million. The Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Transmission

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

Hydro Relicensing

In July 2005, the Company filed two applications with the FERC for new 50-year licenses for the Company’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expire in 2007.

     In 2006, the Company will initiate the process of developing a relicensing application for the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013.

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     Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to the Company. The final outcome of these matters cannot be determined at this time.

Nuclear Relicensing

The Company filed an application with the Nuclear Regulatory Commission (NRC) in September 2003 to extend the operating license for Plant Farley for an additional 20 years. In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved the Company’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. See Note 1 to the financial statements under “Nuclear Decommissioning” for additional information.

PSC Matters

Retail Rate Adjustments

In October 2005, the Alabama PSC approved a revision to Rate RSE requested by the Company. Effective January 2007, Rate RSE adjustments will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to 5 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. If the Company’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate RSE” for further information.

     The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate Certificated New Plant (CNP). In October 2004, the Alabama PSC amended Rate CNP to also allow for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 1.0 percent in January 2005 and 1.2 percent in January 2006. It is currently anticipated that retail rates will increase approximately 0.5 percent in 2007. In conjunction with the Alabama PSC’s approval of this rate mechanism, the Company agreed to a moratorium through 2006 on retail rate increases under Rate RSE.

     Effective July 2003, the Company’s retail rates were adjusted by approximately 2.6 percent under Rate CNP as a result of two new certificated PPAs that began in June 2003. An additional increase of 0.8 percent in retail rates, or $25 million annually, was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. The projected annual true-up adjustment to be effective in April 2006 is expected to increase retail rates by 0.5 percent, or $19 million annually. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate CNP” for additional information.

Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Alabama PSC. As a result of increased fuel costs for coal and gas, the Company filed a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). In December 2005, the Alabama PSC approved an increase of the energy billing factor for retail customers from 1.788 cents per KWH to 2.400 cents per KWH, effective with billings beginning January 2006. This change to the billing factor represents on average an increase of approximately $6.12 per month for a customer billing of 1,000 KWHs. This approved increase was intended to allow for the recovery of energy costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2007. In addition, during 2007, the

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Company will be allowed to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. As a result of the order, the Company reclassified $186.9 million of the under-recovered regulatory clause revenues from current assets to deferred charges and other assets in the balance sheet as of December 31, 2005. See Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.

     Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this approved increase in the billing factor will have no significant effect on the Company’s revenues or net income, but will increase annual cash flow.

Natural Disaster Cost Recovery

The Company maintains a reserve for operation and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.

     In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately $28 million), which resulted in a negative balance in the natural disaster reserve (NDR). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately $30 million). See Note 1 and Note 3 to the financial statements under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, for additional information on these reserves. The natural disaster reserve deficit balance at December 31, 2005 was $50.6 million.

     In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24-month period. The maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.

     As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income but will increase the annual cash flow.

Other Matters

In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $21 million, $36 million, and $52 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $28 million, $22 million, and $23 million in 2005, 2004, and 2003, respectively. Both pension and postretirement benefit costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

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

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

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

     As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

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

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

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

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

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

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

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Unbilled Revenues

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

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $35 million. The adoption of FIN 47 did not have any effect on the Company’s income statement.

Stock Options

On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be strong at December 31, 2005. Net cash flow from operating activities totaled $0.9 billion, $1.0 billion, and $1.1 billion for 2005, 2004, and 2003, respectively. The $106 million decrease for 2005 in operating activities primarily relates to an increase in under recovered fuel cost and storm damage costs related to Hurricanes Dennis and Katrina. These increases were partially offset by the deferral of income tax liabilities arising from accelerated depreciation deductions. The $104 million decrease from 2003 to 2004 resulted from under recovered fuel cost and storm damage costs related to Hurricane Ivan partially offset by accelerated depreciation reductions. Fuel and storm damage costs are recoverable in future periods. Under recovered fuel cost is included in the balance sheets as under recovered regulatory clause revenue and deferred under recovered regulatory clause revenues. Under recovered storm damage cost is included in the balance sheets as other current assets and other regulatory assets. See FUTURE EARNINGS POTENTIAL — “Fuel Cost Recovery” and “Natural Disaster Cost Recovery” herein for additional information.

     Significant balance sheet changes for 2005 include an increase of $668 million in gross plant. In 2004 significant balance sheet changes included the $478 million increase in long-term debt primarily due to the replacement of debt due within one year with long-term debt, and an increase of $408 million in gross plant.

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     The Company’s ratio of common equity to total capitalization — including short-term debt — was 42.2 percent in 2005, 42.6 percent in 2004, and 43.3 percent in 2003. See Note 6 to the financial statements for additional information.

     The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. In recent years, the Company has primarily utilized unsecured debt, preferred stock, and preferred securities. However, the type and timing of any financings — if needed — will depend on market conditions and regulatory approval.

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

     The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

     The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business.

     To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2006, the Company had approximately $22 million of cash and cash equivalents and $878 million of unused credit arrangements with banks, as described below. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.

     The Company maintains committed lines of credit in the amount of $878 million, of which $428 million will expire at various times during 2006. $251 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional one-year period. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support.

     As of December 31, 2005 the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement. As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding.

Financing Activities

During 2005, the Company issued $250 million of long-term debt. In addition, the Company issued one million new shares of common stock to Southern Company at $40.00 a share and realized proceeds of $40 million. The proceeds of these issues were used to repay short-term indebtedness, and for other general corporate purposes. In November 2005, the Company incurred obligations in connection with the issuance of $21.5 million of variable rate pollution control bonds. The proceeds were used to refund $21.5 million 5.50% fixed rate pollution control bonds.

     In January and February 2006, the Company issued $600 million of long-term debt. The proceeds of these issues were used to repay short-term indebtedness and for other general corporate purposes. In conjunction with these transactions, the Company terminated $600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period.

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Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, the Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, the Company’s exposure to these agreements was not material.

Market Price Risk

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

     To mitigate future exposure to changes in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. The weighted average interest rate on $271.5 million of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.45 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $2.7 million at January 1, 2006. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

     To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.

     In addition, the Company’s Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company’s electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75 percent of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the Company’s natural gas budget for that year.

     At December 31, 2005, exposure from these activities was not material to the Company’s financial position, results of operations, or cash flows. The changes in fair value of energy related derivative contracts and year-end valuations were as follows at December 31:

	Changes in Fair Value
	2005			2004
	(in thousands)
Contracts beginning of year	$	4,017		$	6,413
Contracts realized or settled		(38,320	)		(26,384	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		63,281			23,988
Contracts end of year	$	28,978		$	4,017

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

	Source of 2005 Year-End
	Valuation Prices
	Total			Maturity
	Fair Value			2006			2007-2008
	(in thousands)
Actively quoted	$	29,177		$	19,392		$	9,785
External sources		(199	)		(199	)		—
Models and other methods		—			—			—
Contracts end of Year	$	28,978		$	19,193		$	9,785

     Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2005, the fair

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

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

	Amounts
	(in thousands)
Regulatory liabilities, net	$	29,044
Other comprehensive income		—
Net income		(66	)
Total fair value	$	28,978

     Unrealized pre-tax gains (losses) on energy contracts recognized in income were not material for any year presented.

     The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $0.9 billion for 2006, $1.1 billion for 2007, and $1.1 billion for 2008. Environmental expenditures included in these amounts are $285 million, $426 million, and $406 million for 2006, 2007, and 2008, respectively (including $305 million on selective catalytic reduction facilities and $658 million on scrubbers). In addition, over the next three years, the Company estimates spending $244 million on Plant Farley (including $184 million for nuclear fuel), $793 million on distribution facilities, and $394 million on transmission additions. See Note 7 to the financial statements under “Construction Program” for additional details.

     Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

     In addition to the funds required for the Company’s construction program, approximately $1.6 billion will be required by the end of 2008 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities and replace these obligations with lower-cost capital if market conditions permit.

     As discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The final installment is scheduled to occur in 2006.

     The Company has also established an external trust fund for postretirement benefits as ordered by the Alabama PSC. The cumulative effect of funding these items over a long period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under “Postretirement Benefits.”

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

II-97

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

Contractual Obligations
			2007-		2009-		After
	2006		2008		2010		2010		Total
	(in millions)
Long-term debt(a) —
Principal	$	546.7	$	1,078.8	$	350.1	$	2,444.4	$	4,420.0
Interest		191.7		325.3		252.7		2,165.7		2,935.4
Commodity derivative obligations(b)		9.3		0.1		—		—		9.4
Preferred stock dividends(c)		24.3		48.6		48.6		—		121.5
Operating leases		23.6		28.5		17.0		29.1		98.2
Purchase commitments(d) —
Capital(e)		950.9		2,208.1		—		—		3,159.0
Coal		1,064.9		1,551.7		863.6		323.6		3,803.8
Nuclear fuel		18.3		20.0		8.6		25.5		72.4
Natural gas(f)		545.2		413.9		45.4		89.4		1,093.9
Purchased power		87.0		177.0		125.0		2.0		391.0
Long-term service agreements		17.8		37.0		38.4		87.4		180.6
Postretirement benefits(g)		24.9		44.6		—		—		69.5
DOE		4.7		—		—		—		4.7
Total	$	3,509.3	$	5,933.6	$	1,749.4	$	5,167.1	$	16,359.4

(a)	All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
(b)	For additional information, see Notes 1 and 6 to the financial statements herein.
(c)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(d)	The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $1.04 billion, $947 million, and $921 million, respectively.
(e)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)	Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)	The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

II-98

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company, and FERC matters;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

II-99

STATEMENTS OF INCOME

For the Years Ended December 31, 2005, 2004, and 2003

Alabama Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Revenues:
Retail sales	$	3,621,421		$	3,292,828		$	3,051,463
Sales for resale —
Non-affiliates		551,408			483,839			487,456
Affiliates		288,956			308,312			277,287
Other revenues		186,039			151,012			143,955
Total operating revenues		4,647,824			4,235,991			3,960,161
Operating Expenses:
Fuel		1,457,301			1,186,472			1,067,821
Purchased power —
Non-affiliates		188,733			186,187			110,885
Affiliates		268,751			226,697			204,353
Other operations		682,308			634,030			611,418
Maintenance		361,832			313,407			309,451
Depreciation and amortization		426,506			425,906			412,919
Taxes other than income taxes		248,854			242,809			228,414
Total operating expenses		3,634,285			3,215,508			2,945,261
Operating Income		1,013,539			1,020,483			1,014,900
Other Income and (Expense):
Allowance for equity funds used during construction		20,281			16,141			12,594
Interest income		17,144			15,677			15,220
Interest expense, net of amounts capitalized		(197,367	)		(193,590	)		(214,302	)
Interest expense to affiliate trusts		(16,237	)		(16,191	)		—
Distributions on mandatorily redeemable preferred securities		—			—			(15,255	)
Other income (expense), net		(20,461	)		(24,728	)		(31,702	)
Total other income and (expense)		(196,640	)		(202,691	)		(233,445	)
Earnings Before Income Taxes		816,899			817,792			781,455
Income taxes		284,715			313,024			290,378
Net Income		532,184			504,768			491,077
Dividends on Preferred Stock		24,289			23,597			18,267
Net Income After Dividends on Preferred Stock	$	507,895		$	481,171		$	472,810

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

II-100

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2004, and 2003
Alabama Power Company 2005 Annual Report

	2005			2004			2003
				(in thousands)
Operating Activities:
Net income	$	532,184		$	504,768		$	491,077
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		498,914			497,010			487,370
Deferred income taxes and investment tax credits, net		106,765			252,858			153,154
Deferred revenues		(12,502	)		(11,510	)		(17,932	)
Allowance for equity funds used during construction		(20,281	)		(16,141	)		(12,594	)
Pension, postretirement, and other employee benefits		(22,117	)		(31,184	)		(38,953	)
Tax benefit of stock options		17,400			10,672			8,680
Hedge settlements		(21,445	)		2,241			(7,957	)
Storm damage accounting order		48,000			—			—
Other, net		(15,491	)		26,826			14,177
Changes in certain current assets and liabilities —
Receivables		(255,481	)		(126,432	)		(13,416	)
Fossil fuel stock		(44,632	)		30,130			(13,251	)
Materials and supplies		(16,935	)		(26,229	)		(4,651	)
Other current assets		1,199			7,438			(953	)
Accounts payable		80,951			(31,899	)		77,128
Accrued taxes		(5,381	)		(24,568	)		(33,507	)
Accrued compensation		3,273			(7,041	)		664
Other current liabilities		33,675			(42,544	)		29,058
Net cash provided from operating activities		908,096			1,014,395			1,118,094
Investing Activities:
Property additions		(860,807	)		(768,334	)		(643,231	)
Nuclear decommissioning trust fund purchases		(224,716	)		(269,277	)		(350,271	)
Nuclear decommissioning trust fund sales		223,850			248,992			329,986
Cost of removal net of salvage		(61,314	)		(37,369	)		(35,440	)
Other		(9,738	)		(5,008	)		1,193
Net cash used for investing activities		(932,725	)		(830,996	)		(697,763	)
Financing Activities:
Increase (decrease) in notes payable, net		315,278			—			(36,991	)
Proceeds —
Senior notes		250,000			900,000			1,415,000
Preferred stock		—			100,000			125,000
Common stock		40,000			40,000			50,000
Capital contributions from parent company		22,473			17,541			17,826
Pollution control bonds		21,450			—			—
Redemptions —
Senior notes		(225,000	)		(725,000	)		(1,507,000	)
Pollution control bonds		(21,450	)		—			—
Other long-term debt		(5	)		(1,445	)		(943	)
Payment of preferred stock dividends		(22,759	)		(23,639	)		(18,181	)
Payment of common stock dividends		(409,900	)		(437,300	)		(430,200	)
Other		(2,697	)		(16,597	)		(14,775	)
Net cash used for financing activities		(32,610	)		(146,440	)		(400,264	)
Net Change in Cash and Cash Equivalents		(57,239	)		36,959			20,067
Cash and Cash Equivalents at Beginning of Year		79,711			42,752			22,685
Cash and Cash Equivalents at End of Year	$	22,472		$	79,711		$	42,752
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $8,161, $6,832, and $6,367 capitalized, respectively)	$	179,658		$	188,556		$	185,272
Income taxes (net of refunds)		159,600			69,068			161,004

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

II-101

BALANCE SHEETS

At December 31, 2005 and 2004

Alabama Power Company 2005 Annual Report

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

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

II-102

BALANCE SHEETS

At December 31, 2005 and 2004

Alabama Power Company 2005 Annual Report

Liabilities and Stockholder's Equity	2005		2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	546,645	$	225,005
Notes payable		315,278		—
Accounts payable —
Affiliated		190,744		141,096
Other		266,174		198,834
Customer deposits		56,709		47,664
Accrued taxes —
Income taxes		63,844		28,498
Other		31,692		29,688
Accrued interest		46,018		40,029
Accrued vacation pay		37,646		36,494
Accrued compensation		92,784		76,858
Other		72,991		34,289
Total current liabilities		1,720,525		858,455
Long-term Debt(See accompanying statements)		3,560,186		3,855,257
Long-term Debt Payable to Affiliated Trusts(See accompanying statements)		309,279		309,279
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,070,746		1,885,120
Deferred credits related to income taxes		101,678		148,395
Accumulated deferred investment tax credits		196,585		205,353
Employee benefit obligations		208,663		194,837
Asset retirement obligations		446,268		383,621
Other cost of removal obligations		600,104		597,147
Other regulatory liabilities		194,135		206,765
Other		23,966		62,045
Total deferred credits and other liabilities		3,842,145		3,683,283
Total Liabilities		9,432,135		8,706,274
Cumulative Preferred Stock(See accompanying statements)		465,046		465,047
Common Stockholder’s Equity(See accompanying statements)		3,792,726		3,610,204
Total Liabilities and Stockholder’s Equity	$	13,689,907	$	12,781,525
Commitments and Contingent Matters(See notes)

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

II-103

STATEMENTS OF CAPITALIZATION

At December 31, 2005 and 2004

Alabama Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long-Term Debt:
Long-term notes payable —
5.49% due November 1, 2005	$	—		$	225,000
2.65% to 2.80% due 2006		520,000			520,000
Floating rate (1.94% at 1/1/06) due 2006		26,500			195,000
3.50% to 7.125% due 2007		500,000			500,000
Floating rate (2.14% at 1/1/06) due 2007		168,500			—
3.125% to 5.375% due 2008		410,000			410,000
Floating rate (4.58% at 1/1/06) due 2009		250,000			250,000
4.70% due 2010		100,000			100,000
5.125% to 5.875% due 2011-2035		1,575,000			1,325,000
Total long-term notes payable	$	3,550,000		$	3,525,000
Other long-term debt —
Pollution control revenue bonds —
Collateralized:
Variable rates (2.01% to 2.16% at 1/1/06) due 2015-2017		89,800			89,800
5.50% due 2024		2,950			24,400
Non-collateralized:
Variable rates (2.01% to 3.74% at 1/1/06) due 2021-2031		467,390			445,940
Total other long-term debt		560,140			560,140
Capitalized lease obligations		564			52
Unamortized debt premium (discount), net		(3,873	)		(4,930	)
Total long-term debt (annual interest requirement — $175.4 million)		4,106,831			4,080,262
Less amount due within one year		546,645			225,005
Long-term debt excluding amount due within one year	$	3,560,186		$	3,855,257			43.8	%		46.8	%

II-104

STATEMENTS OF CAPITALIZATION(continued)

At December 31, 2005 and 2004

Alabama Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long-term Debt Payable to Affiliated Trusts:
4.75% to 5.5% due 2042 (annual interest requirement — $16.2 million)		309,279			309,279			3.8			3.8
Cumulative Preferred Stock:
$100 par or stated value — 4.20% to 4.92%
Authorized — 3,850,000 shares
Outstanding — 475,115 shares		47,610			47,611
$1 par value — 4.95% to 5.83%
Authorized — 27,500,000 shares
Outstanding — 12,000,000 shares: $25 stated value		294,105			294,105
Outstanding — 1,250 shares: $100,000 stated value		123,331			123,331
Total cumulative preferred stock (annual dividend requirement — $24.3 million)		465,046			465,047			5.7			5.6
Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 15,000,000 shares
Outstanding - 9,250,000 shares in 2005 and 8,250,000 shares in 2004		370,000			330,000
Paid-in capital		1,995,056			1,955,183
Retained earnings		1,439,144			1,341,049
Accumulated other comprehensive income (loss)		(11,474	)		(16,028	)
Total common stockholder’s equity		3,792,726			3,610,204			46.7			43.8
Total Capitalization	$	8,127,237		$	8,239,787			100.0	%		100.0	%

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

II-105

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

For the Years Ended December 31, 2005, 2004, and 2003

Alabama Power Company 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
	(in thousands)
Balance at December 31, 2002	$	240,000	$	1,900,563		$	1,250,594		$	(13,417	)	$	3,377,740
Net income after dividends on preferred stock		—		—			472,810			—			472,810
Issuance of common stock		50,000		—			—			—			50,000
Capital contributions from parent company		—		26,506			—			—			26,506
Other comprehensive income (loss)		—		—			—			5,450			5,450
Cash dividends on common stock		—		—			(430,200	)		—			(430,200	)
Other		—		—			(1,646	)		—			(1,646	)
Balance at December 31, 2003		290,000		1,927,069			1,291,558			(7,967	)		3,500,660
Net income after dividends on preferred stock		—		—			481,171			—			481,171
Issuance of common stock		40,000		—			—			—			40,000
Capital contributions from parent company		—		28,213			—			—			28,213
Other comprehensive income (loss)		—		—			—			(8,061	)		(8,061	)
Cash dividends on common stock		—		—			(437,300	)		—			(437,300	)
Other		—		(99	)		5,620			—			5,521
Balance at December 31, 2004		330,000		1,955,183			1,341,049			(16,028	)		3,610,204
Net income after dividends on preferred stock		—		—			507,895			—			507,895
Issuance of common stock		40,000		—			—			—			40,000
Capital contributions from parent company		—		39,873			—			—			39,873
Other comprehensive income (loss)		—		—			—			4,554			4,554
Cash dividends on common stock		—		—			(409,900	)		—			(409,900	)
Other		—		—			100			—			100
Balance at December 31, 2005	$	370,000	$	1,995,056		$	1,439,144		$	(11,474	)	$	3,792,726

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

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2005, 2004, and 2003

Alabama Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Net income after dividends on preferred stock	$	507,895		$	481,171		$	472,810
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(1,422), $(2,482) and $(2,301), respectively		(2,338	)		(4,083	)		(3,785	)
Change in fair value of marketable securities, net of tax of $252		—			414			—
Changes in fair value of qualifying hedges, net of tax of $5,523, $(4,807) and $1,330, respectively		9,085			(7,906	)		2,188
Less: Reclassification adjustment for amounts included in net income, net of tax of $(1,333), $2,136 and $4,285, respectively		(2,193	)		3,514			7,047
Total other comprehensive income (loss)		4,554			(8,061	)		5,450
Comprehensive Income	$	512,449		$	473,110		$	478,260

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

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NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies — the Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company — provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power — related to jointly-owned generating facilities, interconnecting transmission lines, or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC). SCS — the system service company — provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

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

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006. Both Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is subject to regulation by the FERC and the Alabama Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $246 million, $224 million, and $217 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, and management believes they are reasonable.

     The Company has an agreement with Southern Nuclear under which Southern Nuclear operates the Company’s Plant Farley and provides the following nuclear-related services at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, statistical analysis, employee relations, and other services with respect to business and operations. Costs for these services amounted to $157 million, $169 million, and $153 million during 2005, 2004, and 2003, respectively.

     The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $8.2 million in 2005, $7.2 million in 2004, and $6.6 million in 2003. See Note 4 for additional information.

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NOTES (continued)
Alabama Power Company 2005 Annual Report

     Southern Company holds a 30 percent ownership interest in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses. Amounts billed under this agreement totaled approximately $31.5 million, $28.7 million, and $27.5 million in 2005, 2004 and 2003, respectively. In addition, the Company purchases synthetic fuel from AFP for use at several of the Company’s plants. Fuel purchases for 2005, 2004, and 2003 totaled $265.7 million, $236.9 million, and $209.2 million, respectively.

     In June 2003, the Company entered into an agreement with Southern Power under which the Company operates and maintains Plant Harris at cost. In 2005, 2004 and 2003, the Company billed Southern Power $1.9 million, $1.8 million and $0.8 million, respectively, for operation and maintenance. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2005, 2004 and 2003 totaled $63.6 million, $59.0 million and $41.7 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company in 2005 was $81.3 million, $65.7 million in 2004, and $33.9 million in 2003. Additionally, the Company recorded $8.3 million of prepaid capacity expenses included in other deferred charges and other assets in the balance sheets at December 31, 2005 and 2004. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information.

     The Company has an agreement with SouthernLINC Wireless to provide digital wireless communications services to the Company. Costs for these services amounted to $5.7 million, $5.3 million, and $4.9 million during 2005, 2004, and 2003, respectively.

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

     The Company provides incidental services to, and receives such services from, other Southern Company subsidiaries which are generally minor in duration and/or amount. However, with the hurricane damage experienced by Georgia Power, Gulf Power and Mississippi Power in the last two years, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, has caused an increase in these activities. The total amount of storm restoration provided to Georgia Power and Gulf Power in 2004 and to Mississippi Power in 2005 was $2.4 million, $2.3 million and $8.0 million, respectively. In 2004 and 2005, the Company received assistance from affiliated companies in the amount of $5.6 million and $5.0 million, respectively, for aid in major storm restoration. These activities were billed at cost.

     The retail operating companies, including the Company, and Southern Power jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.

Revenues

Energy and other revenues are recognized as services are provided. Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balance and files for a revised fuel rate when management deems appropriate. See “Retail Regulatory Matters – Fuel Cost Recovery” in Note 3 for additional information.

     The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged less than one percent of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel

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Alabama Power Company 2005 Annual Report

expense totaled $64 million in 2005, $61 million in 2004, and $64 million in 2003.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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

	2005			2004			Note
	(in millions)
Deferred income tax charges	$	389		$	317			(a	)
Loss on reacquired debt		102			109			(b	)
DOE assessments		5			9			(c	)
Vacation pay		38			36			(d	)
Rate CNP under recovery		31			18			(e	)
Natural disaster reserve		51			38			(e	)
Fuel-hedging assets		9			6			(f	)
Other assets		13			13			(e	)
Asset retirement obligations		(139	)		(159	)		(a	)
Other cost of removal obligations		(600	)		(597	)		(a	)
Deferred income tax credits		(102	)		(148	)		(a	)
Deferred purchased power		(19	)		(19	)		(e	)
Mine reclamation and remediation		(16	)		(25	)		(e	)
Fuel-hedging liabilities		(38	)		(10	)		(f	)
Other liabilities		(11	)		(1	)		(e	)
Total	$	(287	)	$	(413	)

Note:	The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered over the remaining life of the original issue which may range up to 50 years.
(c)	Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually from 1993 through 2006.
(d)	Recorded as earned by employees and recovered as paid, generally within one year.
(e)	Recorded and recovered or amortized as approved by the Alabama PSC.
(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clauses.

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

Nuclear Fuel Disposal Costs

The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Construction of an on-site dry spent fuel storage facility at Plant Farley was completed in 2005 and can be expanded to accommodate spent fuel through the life of the plant.

     Also, the Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment has been paid over a 15 year period; the final installment is scheduled to occur in 2006. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability at December 31, 2005 under this law to be approximately $5 million.

Income Taxes

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

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

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Alabama Power Company 2005 Annual Report

     The Company’s property, plant, and equipment consisted of the following at December 31 (in millions):

	2005		2004
Generation	$	7,971	$	7,635
Transmission		2,205		2,097
Distribution		4,115		3,922
General		1,000		969
Plant acquisition adjustment		9		9
Total plant in service	$	15,300	$	14,632

     The cost of replacements of property — exclusive of minor items of property — is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. The Company accrues estimated refueling costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2005, the Company accrued $28 million and paid $19.7 million for an outage at Unit 2. At December 31, 2005, the reserve balance totaled $7.5 million and is included in the balance sheet in other regulatory liabilities.

Depreciation and Amortization

Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9 percent in 2005, 3.0 percent in 2004, and 3.1 percent in 2003. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs of an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or Interpretation No. 47.

     The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facility, Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2005 was $467 million. See “Nuclear Decommissioning” herein for further information. In addition, the Company recognized asset retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, the Company recognized additional asset retirement obligations (and assets) of $35 million, related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. The Company has also identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets.

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NOTES (continued)
Alabama Power Company 2005 Annual Report

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

	2005		2004
	(in millions)
Balance beginning of year	$	384	$	359
Liabilities incurred		36		—
Liabilities settled		—		—
Accretion		26		25
Cash flow revisions		—		—
Balance end of year	$	446	$	384

     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $417 million.

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:

	Unrealized		Unrealized
2005	Gains		Losses			Fair Value
	(in millions)
Equity	$	78.9	$	(7.7	)	$	275.3
Debt		1.3		(1.6	)		106.1
Other		17.0		—			85.6
Total	$	97.2	$	(9.3	)	$	467.0

	Unrealized		Unrealized
2004	Gains		Losses			Fair Value
	(in millions)
Equity	$	71.3	$	(4.3	)	$	258.1
Debt		3.2		(0.6	)		95.5
Other		13.6		(0.2	)		92.0
Total	$	88.1	$	(5.1	)	$	445.6

     The contractual maturities of debt securities at December 31, 2005 are as follows: $14.1 million in 2006; $55.2 million in 2007-2010; $27.1 million in 2011-2015; and $8.3 million thereafter.

     Sales of the securities held in the trust funds resulted in proceeds of $223.8 million, $249.0 million, and $330.0 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $9.9 million, $7.5 million and $(1.7) million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and do not represent any impairment of the underlying investments.

     The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. At December 31, 2005, the accumulated provisions for decommissioning were as follows:

	(in millions)
External trust funds, at fair value	$	467
Internal reserves		28
Total	$	495

     Site study cost is the estimate to decommission the facility as of the site study year. The estimated costs of decommissioning, based on the most current study performed in 2003 for Plant Farley were as follows:

Decommissioning periods:
Beginning year	2017
Completion year	2046

	(in millions)
Site study costs:
Radiated structures	$	892
Non-radiated structures		63
Total	$	955

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

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Alabama Power Company 2005 Annual Report

     All of the Company’s decommissioning costs for ratemaking are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and a trust earnings rate of 7.0 percent. Another significant assumption used was the change in the operating license for Plant Farley.

     In May 2005, the NRC granted the Company a 20-year extension of the operating license for both units at Plant Farley. As a result of the license extension, amounts previously contributed to the external trust are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved the Company’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the external trust. The Company will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with the NRC and other applicable requirements. The approved suspension does not affect the transfer of internal reserves (less than $1 million annually) previously collected from customers prior to the establishment of the external trust.

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 8.8 percent in 2005, 8.6 percent in 2004, and 9.0 percent in 2003. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 5.0 percent in 2005, 4.2 percent in 2004, and 3.5 percent in 2003.

Impairment of Long-Lived Assets and Intangibles

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

Natural Disaster Reserve

In accordance with an Alabama PSC order, the Company has established a natural disaster reserve (NDR) to cover the cost of uninsured damages from major storms to transmission and distribution facilities. The Company may collect a monthly NDR charge per account that consists of two components beginning January 1, 2006. The first component is intended to establish and maintain a reserve for future storms and is an on-going part of customer billing. This plan has a target reserve balance of $75 million that could be achieved in five years. The second component of the NDR charge is intended to allow recovery of the deferred Hurricanes Dennis- and Katrina-related operation and maintenance costs and to set in place a mechanism to replenish the natural disaster reserve should any future storms deplete the natural disaster reserve. The Alabama PSC order gives the Company authority to have a negative NDR balance when costs of uninsured storm damage exceed any established NDR balance. This second component allows for the recovery of a negative balance over a 24-month period. The maximum total NDR charge consisting of both components is $10 per month per account for non-residential customers and $5 per month per account for residential customers.

     As revenue from the natural disaster reserve charge is recognized, an equal amount of operation and maintenance expense related to the natural disaster reserve will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.

Environmental Cost Recovery

The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Alabama PSC, these rates are adjusted

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annually. See Note 3 under “Retail Regulatory Matters – Rate Adjustment Procedures” for additional information.

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.

For pro forma purposes, Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on earnings is as follows:

	As		Options			Pro
Net Income	Reported		Impact			Forma
	(in thousands)
2005	$	507,895	$	(2,829	)	$	505,066
2004		481,171		(2,575	)		478,596
2003		472,810		(2,762	)		470,048

     The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:

	2005			2004			2003
Interest rate		3.9	%		3.1	%		2.7	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.9	%		19.6	%		23.6	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

Financial Instruments

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

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

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Alabama Power Company 2005 Annual Report

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

	Carrying		Fair
	Amount		Value
	(in millions)
Long-term debt:
2005	$	4,416	$	4,403
2004		4,389		4,454

     The fair values were based on either closing market price or closing price of comparable instruments.

Comprehensive Income

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

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information. However, the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.

Investments

The Company maintains an investment in a debt security that matures in 2018 and is classified as available-for-sale. This security is included in the balance sheets under Other Property and Investments-Other and totaled $4.4 million and $4.8 million at December 31, 2005 and 2004, respectively. Because the interest rate resets weekly, the carrying value approximates the fair market value.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly-compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the Alabama PSC. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately $24.9 million.

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

Pension Plans

The accumulated benefit obligation for the pension plans was $1.3 billion in 2005 and $1.2 billion in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

	Projected
	Benefit Obligations
	2005			2004
	(in millions)
Balance at beginning of year	$	1,325		$	1,200
Service cost		33			30
Interest cost		74			71
Benefits paid		(65	)		(64	)
Plan amendments		8			1
Actuarial (gain) loss		46			87
Balance at end of year	$	1,421		$	1,325

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	1,676		$	1,583
Actual return on plan assets		262			157
Employer contributions		4			4
Benefits paid		(67	)		(68	)
Balance at end of year	$	1,875		$	1,676

     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $1.3 billion and $85 million, respectively. All plan assets are related to the qualified plan.

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Alabama Power Company 2005 Annual Report

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

	Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	454		$	351
Unrecognized prior service cost		79			80
Unrecognized net (gain) loss		(52	)		27
Prepaid pension asset, net	$	481		$	458

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

	2005			2004
	(in millions)
Prepaid pension asset	$	515		$	489
Employee benefit obligations		(67	)		(60	)
Intangible asset		10			10
Accumulated other comprehensive income		23			19
Prepaid pension asset, net	$	481		$	458

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

	2005			2004			2003
	(in millions)
Service cost	$	33		$	30		$	27
Interest cost		74			71			68
Expected return on plan assets		(139	)		(138	)		(138	)
Recognized net (gain) loss		2			(3	)		(12	)
Net amortization		9			4			3
Net pension cost (income)	$	(21	)	$	(36	)	$	(52	)

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligations for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	Benefit
	Payments
	(in millions)
2006	$	65.2
2007		66.6
2008		68.4
2009		70.6
2010		73.6
2011 to 2015	$	429.2

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

	Accumulated
	Benefit Obligations
	2005			2004
	(in millions)
Balance at beginning of year	$	465		$	441
Service cost		7			7
Interest cost		26			24
Benefits paid		(21	)		(18	)
Actuarial (gain) loss		13			11
Balance at end of year	$	490		$	465

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	212		$	186
Actual return on plan assets		28			24
Employer contributions		26			20
Benefits paid		(21	)		(18	)
Balance at end of year	$	245		$	212

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

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Alabama Power Company 2005 Annual Report

	Plan Assets
	Target			2005			2004
Domestic equity		49	%		53	%		46	%
International equity		11			11			13
Fixed income		29			28			33
Real estate		7			6			5
Private equity		4			2			3
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	(245	)	$	(253	)
Unrecognized transition obligation		29			33
Unrecognized prior service cost		64			68
Unrecognized net loss (gain)		85			87
Fourth quarter contributions		12			9
Accrued liability recognized in the balance sheets	$	(55	)	$	(56	)

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

	2005			2004			2003
	(in millions)
Service cost	$	7		$	7		$	6
Interest cost		26			24			25
Expected return on plan assets		(16	)		(18	)		(17	)
Net amortization		11			9			9
Net postretirement cost	$	28		$	22		$	23

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $3.2 million and $8.7 million, respectively, and is expected to have a similar impact on future expenses.

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

	Benefit		Subsidy
	Payments		Receipts			Total
	(in millions)
2006	$	24.5	$	(2.6	)	$	21.9
2007		25.6		(3.1	)		22.5
2008		27.8		(3.5	)		24.3
2009		30.4		(3.8	)		26.6
2010		32.9		(4.1	)		28.8
2011 to 2015	$	180.2	$	(27.7	)	$	152.5

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:

	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00			3.50			3.75
Long-term return on plan assets		8.50			8.50			8.50

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	40	$	35
Service and interest costs		3		2

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $14 million, $13 million, and $12 million, respectively.

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Alabama Power Company 2005 Annual Report

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the Company’s financial statements.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against the Company, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Northern District of Georgia granted the Company’s motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against the Company in the U.S. District Court for the Northern District of Alabama. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of the Company on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, the Company and the EPA are currently participating in mediation with respect to the EPA’s claims.

      The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

      In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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Alabama Power Company 2005 Annual Report

      In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The 15-month refund period will end on October 19, 2006. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

      The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are subject to refund to the extent the FERC orders any changes to the IIC.

      The Company believes that there is no meritorious basis for these allegations and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. The Company has also received similar requests from other entities totaling approximately $7 million. The Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Retail Regulatory Matters

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

Rate RSE

The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments based upon the Company’s earned return on end-of-period retail common equity. Prior to January 2007, annual adjustments are limited to 3 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. On October 4, 2005, the Alabama PSC approved a revision to

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Alabama Power Company 2005 Annual Report

Rate RSE. Effective January 2007 and thereafter Rate RSE adjustments are made based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0 percent per year and any annual adjustment is limited to 5.0 percent. The range of return on common equity, on which such adjustments are based, remains unchanged. If the Company’s actual return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual return on common equity fall below the allowed equity return range. The Company will make its initial submission of projected data for calendar year 2007 by December 1, 2006. In conjunction with the Alabama PSC approval of a rate mechanism to recover retail costs associated with environmental laws and regulations in October 2004, the Company agreed to a moratorium on retail rate increases under Rate RSE through 2006. See “Rate CNP” herein for additional information.

Rate CNP

The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the placing of new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP). In October 2004, the Alabama PSC approved a request by the Company to amend Rate CNP to provide for the recovery of retail costs associated with environmental laws and regulations. Environmental costs to be recovered include operation and maintenance expenses, depreciation and a return on invested capital. This component of Rate CNP began operation in January 2005.

      To recover certificated purchased power costs under Rate CNP, increases of 2.6 percent in retail rates, or $79 million annually were effective July 2003 and 0.8 percent in retail rates, or $25 million annually were effective July 2004 for certificated purchase power cost. In April 2005, an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. In April 2006, an annual true-up adjustment to Rate CNP is expected to increase retail rates by approximately 0.5 percent, or $19 million annually.

      The retail rates associated with the recovery of retail costs associated with environmental laws and regulations under Rate CNP are adjusted annually in January. Retail rates increased approximately 1.0 percent in 2005, or $33 million and approximately 1.2 percent in 2006, or $43 million.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Alabama PSC. The Company can change the retail energy cost recovery rate after submitting to the Alabama PSC an estimate of future energy costs and the current over or under recovered balance. In response to such a request, the Alabama PSC may conduct a public hearing prior to its ruling. Alternatively, the retail energy cost recovery rates requested by the Company will become effective 45 days after the initial request.

      In December 2005, the Alabama PSC approved the Company’s request to increase the retail energy cost recovery rate to 2.400 cents per kilowatt-hour, effective with billings beginning January 1, 2006.

Natural Disaster Cost Recovery

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

      In February and December 2005, the Company requested and received Alabama PSC approval of an accounting order that allowed the Company to immediately return certain regulatory liabilities to the retail customers. These orders also allowed the Company to simultaneously recover from customers an accrual of approximately $48 million to primarily offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effects of these orders had no impact on the Company’s net income in 2005.

      On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant damage in parts of the service territory of the Company. Approximately 241,000 and 637,000 of the Company’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina, respectively. The Company sustained significant damage to its distribution and transmission facilities during these storms.

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Alabama Power Company 2005 Annual Report

      In August 2005, the Company received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (approximately $28 million). In October 2005, the Company also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (approximately $30 million). The NDR balance at December 31, 2005 was a regulatory asset of $50.6 million.

      In December 2005, the Alabama PSC approved a request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of uninsured storm damage exceed any established reserve balance. The order also approved a separate monthly NDR charge consisting of two components beginning January 2006. The first component is intended to establish and maintain a target reserve balance of $75 million for future storms and is an on-going part of customer billing. The Company currently expects that the target reserve balance could be achieved within five years. The second component of the NDR charge is intended to allow recovery of the existing deferred hurricane related operation and maintenance costs and any future reserve deficits over a 24 month period. The maximum total NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account.

      As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow.

4. JOINT OWNERSHIP AGREEMENTS

The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice. The Company’s share of purchased power totaled $90 million in 2005, $86 million in 2004, and $87 million in 2003 and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method.

      In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.

      At December 31, 2005, the capitalization of SEGCO consisted of $60 million of equity and $89 million of debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $7.7 million in 2005, $12.0 million in 2004, and $2.3 million in 2003, of which one-half of each was paid to the Company. In addition, the Company recognizes 50 percent of SEGCO’s net income.

      In addition to the Company’s ownership of SEGCO, the Company’s percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2005 is as follows:

	Total
	Megawatt		Company
Facility (Type)	Capacity		Ownership
Greene County		500		60.00%	(1)
Plant Miller
Units 1 and 2		1,320		91.84%	(2)

(1)	Jointly owned with an affiliate, Mississippi Power.
(2)	Jointly owned with Alabama Electric Cooperative, Inc.

	Company		Accumulated
Facility	Investment		Depreciation
	(in millions)
Greene County	$	115	$	60
Plant Miller
Units 1 and 2		940		374

At December 31, 2005, the Company’s Plant Miller portion of construction work in progress was $4.4 million.

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Alabama Power Company 2005 Annual Report

      The Company has contracted to operate and maintain the jointly owned facilities as agent for their co-owners. The Company’s proportionate share of its plant operating expenses is included in operating expenses in the statements of income.

5. INCOME TAXES

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

      In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. At December 31, 2005 and 2004, the Company had $20.4 million and $21.4 million in accumulated deferred income taxes and $2.0 million and $2.3 million in accrued taxes – income taxes, respectively, payable to these subsidiaries, on the balance sheets.

      At December 31, 2005, the Company’s tax-related regulatory assets and liabilities were $389 million and $102 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to taxes applicable to capitalized interest, and to deferred taxes previously recognized at rates different than the current enacted tax law. These liabilities are primarily attributable to unamortized investment tax credits.

      Details of the income tax provisions are as follows:

	2005		2004		2003
	(in millions)
Federal—
Current	$	151	$	44	$	111
Deferred		81		219		137
		232		263		248
State —
Current		27		16		26
Deferred		26		34		16
		53		50		42
Total	$	285	$	313	$	290

      The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	1,626		$	1,524
Property basis differences		440			416
Premium on reacquired debt		42			45
Pensions		148			136
Fuel clause under recovered		138			48
Storm reserve		26			20
Other		46			36
Total		2,466			2,225
Deferred tax assets:
Federal effect of state deferred taxes		114			112
State effect of federal deferred taxes		87			110
Unbilled revenue		22			22
Pension and other benefits		20			16
Other comprehensive losses		19			16
Other		69			36
Total		331			312
Total deferred tax liabilities, net		2,135			1,913
Portion included in current (liabilities) assets, net		(64	)		(28	)
Accumulated deferred income taxes in the balance sheets	$	2,071		$	1,885

      In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8.8 million in 2005, $11 million in 2004, and $11 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

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Alabama Power Company 2005 Annual Report

     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2005			2004			2003
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		4.2			4.0			3.5
Non-deductible book depreciation		1.1			1.1			1.2
Differences in prior years’ deferred and current tax rates		(4.1	)		(0.8	)		(0.9	)
Other		(1.3	)		(1.0	)		(1.6	)
Effective income tax rate		34.9	%		38.3	%		37.2	%

     In accordance with Alabama PSC orders, the Company returned approximately $30 million of excess deferred income taxes to its ratepayers in 2005, resulting in causing 3.6 percent of the “Difference in prior years’ deferred and current tax rates” in the table above. See Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Cost Recovery” for additional information.

6. FINANCING

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

The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $309 million, which constitute substantially all assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2005, preferred securities of $300 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

First Mortgage Bonds

The Company had a firm power sales contract with the Alabama Municipal Electric Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts). Under the terms of the contract, the Company received payments from AMEA representing the net present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate of 11.19 percent. These payments were recognized as operating revenues and the discount was amortized to other interest expense as scheduled capacity was made available over the terms of the contract.

     To secure AMEA’s advance payments and the Company’s performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest was payable on such bonds unless and until a default by the Company occurred. As the liquidated damages declined, a portion of the bond equal to the decrease was returned to the Company. At December 31, 2005, the bonds that were previously held in escrow were returned to the Company due to the fulfillment of the contract obligation.

Pollution Control Bonds

Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $92.8 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements.

Senior Notes

The Company issued a total of $250 million of unsecured senior notes in 2005. The proceeds of these issues were used to repay short-term indebtedness, and for other general corporate purposes.

     At December 31, 2005 and 2004, the Company had $3.6 billion and $3.5 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $246 million at December 31, 2005.

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Alabama Power Company 2005 Annual Report

Securities Due Within One Year

At December 31, 2005 and 2004, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $547 million and $225 million respectively.

     Debt serial maturities through 2010 applicable to total long-term debt are as follows: $547 million in 2006; $669 million in 2007; $410 million in 2008; $250 million in 2009; and $100 million in 2010.

Assets Subject to Lien

The Company’s mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company’s fixed property and franchises.

Bank Credit Arrangements

The Company maintains committed lines of credit in the amount of $878 million (including $563 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $428 million will expire at various times during 2006. $251 million of the credit facilities expiring in 2006 allow for the execution of one-year term loans. All of the credit arrangements require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Commitment fees are less than 1/4 of 1 percent for the Company. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit arrangements, a fee is also paid to the agent banks.

     Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65 percent of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2005, the Company was in compliance with the debt limit covenants. In addition, the credit arrangements typically contain cross default provisions that would be triggered if the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None of the arrangements contain material adverse change clauses at the time of borrowings.

     The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. In addition, the Company borrows from time to time through extendible commercial note programs and uncommitted credit arrangements. As of December 31, 2005, the Company had $136 million in commercial paper outstanding, $55 million in extendible commercial notes outstanding, and $125 million in loans outstanding under an uncommitted credit arrangement. As of December 31, 2004, the Company had no extendible commercial notes and no commercial paper outstanding. During 2005, the peak amount outstanding for short-term borrowings was $315 million and the average amount outstanding was $31 million. The average annual interest rate on short-term borrowings in 2005 was 4.04 percent. Short-term borrowings are included in notes payable in the balance sheets.

     At December 31, 2005, the Company had regulatory approval to have outstanding up to $1.4 billion of short-term borrowings.

Financial Instruments

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the instruction of the Alabama PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005, 2004, and 2003.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	29,044
Net income		(66	)
Total fair value	$	28,978

     The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2008.

     The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted

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Alabama Power Company 2005 Annual Report

transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

     At December 31, 2005, the Company had $1.3 billion notional amount of interest rate swaps outstanding with net fair value gains of $25.3 million as follows:

	Weighted Average					Fair
	Fixed					Value
	Rate			Notional		Gain/
Maturity	Paid			Amount		(Loss)
				(in millions)
2006		1.89		$	195	$	2.5
2007		2.01	*		536		7.3
2016		4.82			300		3.0
2016		4.42			300		12.5

* Hedged using the Bond Market Association Municipal Swap Index.

     The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2005, 2004, and 2003, the Company settled gains (losses) of $(21.4) million, $5.5 million and $(8.0) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the underlying related debt.

     For the years 2005, 2004 and 2003, approximately $3.5 million, $(6.3) million, and $(11.3) million, respectively, of pre-tax gains/(losses) were reclassified from other comprehensive income to interest expense. For 2006, pre-tax gains of approximately $9.4 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2016 and has gains/losses that are being amortized through 2035.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $0.9 billion in 2006, $1.1 billion in 2007, and $1.1 billion in 2008. These amounts include $18 million, $11 million, and $9 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments” herein. The construction programs are subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for existing generation, transmission, and distribution facilities, will continue.

Long-Term Service Agreements

The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. The LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

     In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $263 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2005, the remaining balance was approximately $181 million. However, the LTSAs contain various cancellation provisions at the option of the Company.

     Payments made to GE prior to the performance of any planned maintenance are recorded as either prepayments or other deferred charges and assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

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Alabama Power Company 2005 Annual Report

Purchased Power Commitments

The Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2005 were as follows:

	Commitments
			Non-
Year	Affiliated		Affiliated		Total
	(in millions)
2006	$	50	$	37	$	87
2007		50		38		88
2008		50		39		89
2009		50		40		90
2010		12		23		35
2011 and thereafter		—		2		2
Total commitments	$	212	$	179	$	391

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005. Total estimated minimum long-term commitments at December 31, 2005 were as follows:

	Natural				Nuclear
Year	Gas		Coal		Fuel
	(in millions)
2006	$	545	$	1,065	$	18
2007		269		1,027		11
2008		145		524		9
2009		26		442		3
2010		19		422		6
2011 and thereafter		89		324		26
Total commitments	$	1,093	$	3,804	$	73

     Additional commitments for fuel will be required to supply the Company’s future needs.

     SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company GAS is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company GAS as a contracting party under these agreements.

Operating Leases

The Company has entered into rental agreements for coal rail cars, vehicles, and other equipment with various terms and expiration dates. These expenses totaled $27.3 million in 2005, $28.3 million in 2004, and $29.5 million in 2003. Of these amounts, $17.8 million, $16.3 million, and $19.4 million for 2005, 2004, and 2003, respectively, relates to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2005, estimated minimum rental commitments for noncancellable operating leases were as follows:

	Rail		Vehicles
Year	Cars		& Other		Total
	(in millions)
2006	$	16.2	$	7.4	$	23.6
2007		8.9		6.1		15.0
2008		8.6		4.9		13.5
2009		4.8		4.6		9.4
2010		3.5		4.1		7.6
2011 and thereafter		24.0		5.1		29.1
Total minimum payments	$	66.0	$	32.2	$	98.2

     In addition to the rental commitments above, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases expire in 2006 and 2009, and the Company’s maximum obligations are $66 million and $20 million, respectively. At the termination of the leases, at the Company’s option, the Company may negotiate an extension, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially eliminate the Company’s payments under the residual value obligations.

     Guarantees

     At December 31, 2005, the Company had outstanding guarantees related to SEGCO’s purchase of certain

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NOTES (continued)
Alabama Power Company 2005 Annual Report

pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets as described above in “Operating Leases.”

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2005, 1,106 current and former employees of the Company participated in this stock option plan. The maximum number of shares of Southern Company common stock that may be issued under the plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2003 to 2005 for the options granted to the Company’s employees under the stock option plan is summarized below:

	Shares			Average
	Subject			Option Price
	to Option			per Share
Balance at December 31, 2002		5,693,923		$	19.72
Options granted		1,201,469			27.98
Options canceled		(6,726	)		23.11
Options exercised		(1,043,013	)		16.16
Balance at December 31, 2003		5,845,653			22.05
Options granted		1,168,140			29.50
Options canceled		(3,379	)		28.82
Options exercised		(1,252,277	)		18.07
Balance at December 31, 2004		5,758,137			24.42
Options granted		1,180,491			32.70
Options canceled		(1,973	)		30.10
Options exercised		(1,708,670	)		21.95
Balance at December 31, 2005		5,227,985		$	27.09
Options exercisable:
At December 31, 2003		3,171,383
At December 31, 2004		3,404,264
At December 31, 2005		2,943,134

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares (in thousands)		700		2,266		2,262
Average remaining life (in years)		4.3		6.3		8.6
Average exercise price	$	17.30	$	26.05	$	31.17
Exercisable:
Shares (in thousands)		700		1,897		346
Average exercise price	$	17.30	$	25.68	$	29.59

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendment Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $10.8 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $201 million per incident but not more than an aggregate of $30 million to be paid for each incident in any one year.

     The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.

     Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

     NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a

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NOTES (continued)
Alabama Power Company 2005 Annual Report

maximum per occurrence per unit limit of $490 million. After this deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL and has elected a 12-week waiting period.

     Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $41 million.

     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all “non-certified” terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property claims stemming from terrorism within a 12 month duration, is $3.2 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.

     For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

     All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Summarized quarterly financial information for 2005 and 2004 are as follows:

					Net Income
					After
					Dividends
Quarter	Operating		Operating		on Preferred
Ended	Revenues		Income		Stock
	(in millions)
March 2005	$	970	$	157	$	93
June 2005		1,086		253		122
September 2005		1,458		443		236
December 2005		1,134		161		57
March 2004	$	960	$	202	$	91
June 2004		1,059		239		104
September 2004		1,246		415		220
December 2004		971		164		66

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

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Alabama Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands)	$	4,647,824	$	4,235,991	$	3,960,161	$	3,710,533	$	3,586,390
Net Income after Dividends on Preferred Stock (in thousands)	$	507,895	$	481,171	$	472,810	$	461,355	$	386,729
Cash Dividends on Common Stock (in thousands)	$	409,900	$	437,300	$	430,200	$	431,000	$	393,900
Return on Average Common Equity (percent)		13.72		13.53		13.75		13.80		11.89
Total Assets (in thousands)	$	13,689,907	$	12,781,525	$	12,099,575	$	11,591,666	$	11,303,605
Gross Property Additions (in thousands)	$	890,062	$	786,298	$	661,154	$	645,262	$	635,540
Capitalization (in thousands) :
Common stock equity	$	3,792,726	$	3,610,204	$	3,500,660	$	3,377,740	$	3,310,877
Preferred stock		465,046		465,047		372,512		247,512		317,512
Mandatorily redeemable preferred securities		—		—		300,000		300,000		347,000
Long-term debt payable to affiliated trusts		309,279		309,279		—		—		—
Long-term debt		3,560,186		3,855,257		3,377,148		2,872,609		3,742,346
Total (excluding amounts due within one year)	$	8,127,237	$	8,239,787	$	7,550,320	$	6,797,861	$	7,717,735
Capitalization Ratios (percent) :
Common stock equity		46.7		43.8		46.4		49.7		42.9
Preferred stock		5.7		5.6		4.9		3.6		4.1
Mandatorily redeemable preferred securities		—		—		4.0		4.4		4.5
Long-term debt payable to affiliated trusts		3.8		3.8		—		—		—
Long-term debt		43.8		46.8		44.7		42.3		48.5
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
First Mortgage Bonds —
Moody’s		A1		A1		A1		A1		A1
Standard and Poor’s		A+		A		A		A		A
Fitch	AA-		AA-			A+		A+		A+
Preferred Stock —
Moody’s	Baa1		Baa1		Baa1		Baa1		Baa1
Standard and Poor’s	BBB+		BBB+		BBB+		BBB+		BBB+
Fitch		A		A		A-		A-		A-
Unsecured Long-Term Debt —
Moody’s		A2		A2		A2		A2		A2
Standard and Poor’s		A		A		A		A		A
Fitch		A+		A+		A		A		A
Customers (year-end) :
Residential		1,184,406		1,170,814		1,160,129		1,148,645		1,139,542
Commercial		212,546		208,547		204,561		203,017		196,617
Industrial		5,492		5,260		5,032		4,874		4,728
Other		759		753		757		789		751
Total		1,403,203		1,385,374		1,370,479		1,357,325		1,341,638
Employees(year-end)		6,621		6,745		6,730		6,715		6,706

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Alabama Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands) :
Residential	$	1,476,211	$	1,346,669	$	1,276,800	$	1,264,431	$	1,138,499
Commercial		1,062,341		980,771		913,697		882,669		829,760
Industrial		1,065,124		948,528		844,538		788,037		763,934
Other		17,745		16,860		16,428		16,080		15,480
Total retail		3,621,421		3,292,828		3,051,463		2,951,217		2,747,673
Sales for resale — non-affiliates		551,408		483,839		487,456		474,291		485,974
Sales for resale — affiliates		288,956		308,312		277,287		188,163		245,189
Total revenues from sales of electricity		4,461,785		4,084,979		3,816,206		3,613,671		3,478,836
Other revenues		186,039		151,012		143,955		96,862		107,554
Total	$	4,647,824	$	4,235,991	$	3,960,161	$	3,710,533	$	3,586,390
Kilowatt-Hour Sales (in thousands) :
Residential		18,073,783		17,368,321		16,959,566		17,402,645		15,880,971
Commercial		14,061,650		13,822,926		13,451,757		13,362,631		12,798,711
Industrial		23,349,769		22,854,399		21,593,519		21,102,568		20,460,022
Other		198,715		198,253		203,178		205,346		198,102
Total retail		55,683,917		54,243,899		52,208,020		52,073,190		49,337,806
Sales for resale — non-affiliates		15,442,728		15,483,420		17,085,376		15,553,545		15,277,839
Sales for resale — affiliates		5,735,429		7,233,880		9,422,301		8,844,050		8,843,094
Total		76,862,074		76,961,199		78,715,697		76,470,785		73,458,739
Average Revenue Per Kilowatt-Hour (cents) :
Residential		8.17		7.75		7.53		7.27		7.17
Commercial		7.55		7.10		6.79		6.61		6.48
Industrial		4.56		4.15		3.91		3.73		3.73
Total retail		6.50		6.07		5.84		5.67		5.57
Sales for resale		3.97		3.49		2.88		2.72		3.03
Total sales		5.80		5.31		4.85		4.73		4.74
Residential Average Annual Kilowatt-Hour Use Per Customer		15,347		14,894		14,688		15,198		13,981
Residential Average Annual Revenue Per Customer	$	1,253	$	1,155	$	1,106	$	1,104	$	1,002
Plant Nameplate Capacity Ratings (year-end) (megawatts)		12,216		12,216		12,174		12,153		12,153
Maximum Peak-Hour Demand (megawatts) :
Winter		9,812		9,556		10,409		9,423		9,300
Summer		11,162		10,938		10,462		10,910		10,241
Annual Load Factor (percent)		63.2		63.2		64.1		62.9		62.5
Plant Availability (percent) :
Fossil-steam		90.5		87.8		85.9		85.8		87.1
Nuclear		92.9		88.7		94.7		93.2		83.7
Source of Energy Supply (percent) :
Coal		59.5		56.5		56.5		55.5		56.8
Nuclear		17.2		16.4		17.0		17.1		15.8
Hydro		5.6		5.6		7.0		5.1		5.1
Gas		6.8		8.9		7.6		11.6		10.7
Purchased power —
From non-affiliates		3.8		5.4		4.1		4.0		4.4
From affiliates		7.1		7.2		7.8		6.7		7.2
Total		100.0		100.0		100.0		100.0		100.0

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GEORGIA POWER COMPANY

FINANCIAL SECTION

II-130

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Georgia Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements (pages II-152 to II-184) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power Company 2005 Annual Report

OVERVIEW

Business Activities

Georgia Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast.

     Many factors affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and fuel prices. In December 2004, the Company completed a major retail rate proceeding that is expected to provide earnings stability (2004 Retail Rate Plan). This regulatory action also enables the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and continued environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future. The Company expects further rate proceedings in 2006 to address fuel cost recovery due to higher than expected fuel costs for coal and natural gas.

     On December 13, 2005, the Company and Savannah Electric and Power Company (Savannah Electric) entered into a merger agreement, under which Savannah Electric will merge into the Company, with the Company continuing as the surviving corporation (the Merger). The Merger must be approved by Savannah Electric’s preferred shareholders and is subject to receipt of certain regulatory approvals from the Federal Energy Regulatory Commission (FERC), the Georgia Public Service Commission (PSC), and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to be completed by July 2006. See FUTURE EARNINGS POTENTIAL – “Merger” and Note 3 to the financial statements under “Retail Regulatory Matters – Merger” for additional information.

Key Performance Indicators

In striving to maximize shareholder value while providing low-cost energy to more than two million customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.

     The Company’s 2005 results compared to its targets for some of these indicators are reflected in the following chart.

Key Performance Indicator	2005 Target Performance	2005 Actual Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season EFOR	2.75% or less	1.42%
Net Income	$678 million	$715 million

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the focus that management places on these indicators, as well as the commitment shown by the employees in achieving or exceeding management’s expectations.

Earnings

The Company’s 2005 earnings totaled $715 million representing a $57 million (8.7 percent) increase over 2004. Operating income increased in 2005 due to higher base retail revenues resulting from the retail rate increase

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

effective January 1, 2005 and more favorable weather, as well as higher wholesale revenues resulting from new contracts effective January 1, 2005, partially offset by increased non-fuel operating expenses. The Company’s 2004 earnings totaled $658 million representing a $27 million (4.3 percent) increase over 2003. Operating income increased in 2004 due to higher base retail revenues attributable to more favorable weather and customer growth during the year, partially offset by higher non-fuel operating expenses. In addition, lower depreciation and amortization expense resulting from a Georgia PSC three-year retail rate plan approved in 2001 (2001 Retail Rate Plan) significantly offset increased purchased power capacity expenses. The Company’s 2003 earnings totaled $631 million, representing a $13 million (2.1 percent) increase over 2002 despite lower base retail revenues resulting from the extremely mild summer weather. Higher wholesale revenues and lower non-fuel operating expenses contributed to the 2003 increase.

RESULTS OF OPERATIONS

A condensed income statement for the Company is as follows:

				Increase (Decrease)
	Amount			From Prior Year
	2005			2005			2004			2003
	(in millions)
Operating revenues	$	6,634		$	1,263		$	457		$	92
Fuel		1,831			598			128			101
Purchased power		1,170			194			200			92
Other operation and maintenance		1,481			81			153			(78	)
Depreciation and amortization		504			229			(74	)		(54	)
Taxes other than income taxes		260			32			15			11
Total operating expenses		5,246			1,134			422			72
Operating income		1,388			129			35			20
Total other income and (expense)		(241	)		(20	)		5			2
Income taxes		431			52			13			9
Net income		716			57			27			13
Dividends on preferred stock		1			—			—			—
Net income after dividends on preferred stock	$	715		$	57		$	27		$	13

Revenues

Operating revenues in 2005, 2004, and 2003 and the percent of change from the prior year are as follows:

	Amount
	2005			2004			2003
	(in millions)
Retail – prior year	$	4,777		$	4,310		$	4,288
Change in -
Base rates		195			—			—
Sales growth		135			151			30
Weather		21			32			(66	)
Fuel cost recovery and other		515			284			58
Retail – current year	$	5,643			4,777			4,310
Sales for resale -
Non-affiliates		519			247			260
Affiliates		265			166			175
Total sales for resale		784			413			435
Other operating revenues		207			181			169
Total operating revenues	$	6,634		$	5,371		$	4,914
Percent change		23.5	%		9.3	%		1.9	%

     Retail base revenues of $3.6 billion in 2005 increased by $351 million (10.9 percent) from 2004 primarily due to the retail rate increase effective January 1, 2005, sustained economic strength, customer growth, more favorable weather, and generally higher prices to large business customers. See Note 3 to the financial statements under “Retail Regulatory Matters – Rate Plans” for additional information. Retail base revenues of $3.2 billion in 2004 increased by $183 million (6.0 percent) from 2003 primarily due to an improved economy, customer growth, generally higher prices to the Company’s large business customers, and more favorable weather. Retail base revenues of $3 billion in 2003 decreased by $36 million (1.2 percent) from 2002 primarily due to extremely mild summer temperatures and the sluggish economy.

     Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased energy, and do not affect net income. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

     Wholesale revenues from sales to non-affiliated utilities were:

	2005		2004		2003
	(in millions)
Unit power sales —
Capacity	$	33	$	31	$	34
Energy		31		33		31
Other power sales —
Capacity and other		155		75		93
Energy		300		108		102
Total	$	519	$	247	$	260

     Revenues from unit power sales contracts remained relatively constant in 2005 and 2004. Revenues from unit power sales contracts decreased slightly in 2003 due to decreased energy sales. Revenues from other non-affiliated sales increased $272 million (148.6 percent) in 2005 and decreased $12 million (6.2 percent) and $8 million (3.9 percent) in 2004 and 2003, respectively. The increase in 2005 is due to new contracts with thirty electric membership corporation customers that went into effect in January 2005 which increased the demand for energy. The capacity component of these transactions increased $73.2 million in 2005 over 2004.

     Revenues from sales to affiliated companies within the Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. In 2005, kilowatt-hour (KWH) energy sales to affiliates increased 1.5 percent due to higher demand, while the increase in associated revenues was 59.4 percent due to higher fuel prices. In 2004, KWH energy sales to affiliates decreased 18.2 percent due to lower demand. However, the decline in associated revenues was only 4.9 percent due to higher fuel prices. In 2003, KWH energy sales to affiliates increased 47.5 percent due to the combination of increased demand by Southern Power to meet contractual obligations and the availability of power due to milder-than-normal weather in the Company’s service territory. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

     Other operating revenues increased $25.7 million (14.2 percent) in 2005 from 2004 primarily due to higher transmission revenues of $16 million related to work performed for the other owners of the integrated transmission system in the State of Georgia and higher revenues under the open access tariff agreement, higher outdoor lighting revenues of $5.4 million, and higher customer fees that went into effect in January 2005 of $5.9 million. Other operating revenues increased $11.7 million (6.9 percent) in 2004 over 2003 primarily due to higher revenues from outdoor lighting of $4.2 million and pole attachment rentals of $4.9 million and higher gains on sales of emission allowances of $2 million. Other operating revenues increased $4 million (2.4 percent) in 2003 from the prior year primarily due to an increase in the open access transmission tariff rate, which increased revenues $7 million, and higher revenues from increased customer demand for outdoor lighting services of $4 million, partially offset by lower revenues from the rental of electric property of $4 million.

Energy Sales

KWH sales for 2005 and the percent change by year were as follows:

	KWH		Percent Change
	2005		2005			2004			2003
	(in billions)
Residential		23.6		2.9	%		5.3	%		(1.7	)%
Commercial		29.8		6.3			4.0			(0.1	)
Industrial		25.0		(5.0	)		2.5			(0.1	)
Other		0.6		(0.1	)		1.1			0.4
Total retail		79.0		1.4			3.8			(0.5	)
Sales for resale -
Non-affiliates		11.2		88.2			(32.5	)		9.5
Affiliates		4.9		1.5			(18.2	)		47.5
Total sales for resale		16.1		49.6			(26.8	)		22.0
Total sales		95.1		7.2			(1.2	)		2.6

     Residential KWH sales increased 2.9 percent in 2005 over 2004 due to more favorable weather, customer growth of 1.7 percent, and a 1.1 percent increase in the average energy consumption per customer. Commercial KWH sales increased 6.3 percent due to more favorable weather, sustained economic strength, customer growth of 1.8 percent, and a reclassification of customers from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC when compared

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

to 2004. Industrial sales decreased 5.0 percent primarily due to this reclassification of customers.

     Residential KWH sales increased 5.3 percent in 2004 from 2003 due to more favorable weather and a 1.9 percent increase in residential customers. Commercial KWH sales increased 4.0 percent in 2004 due to an improved economy and a 2.8 percent increase in commercial customers. Industrial sales increased 2.5 percent in 2004 due to the improved economy.

     Residential KWH sales decreased 1.7 percent in 2003 from 2002 due to the effect of the milder summer weather, despite the 2.0 percent increase in residential customers. Commercial KWH sales in 2003 declined slightly due to the milder summer weather, while industrial KWH sales declined slightly due to the sluggish economy. Average retail sales growth assuming normal weather is expected to be 2.1 percent from 2006 to 2010.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of generating units. The amount and sources of generation, the average cost of fuel per net KWH generated, and the average cost of purchased power per net KWH were as follows:

	2005		2004		2003
Total generation (billions of KWH)		80.5		71.5		73.1
Sources of generation (percent) —
Coal		75.3		75.4		75.4
Nuclear		18.6		22.5		21.6
Hydro		2.4		2.0		2.7
Oil and gas		3.7		0.1		0.3
Average cost of fuel per net KWH generated (cents) —		2.04		1.55		1.46
Average cost of purchased power per net KWH (cents) —		7.25		5.17		4.03

     Fuel expense increased 48.5 percent in 2005 from the prior year primarily due to an increase in the average cost of fuel, particularly natural gas, and a 12.3 percent increase in generation to meet higher demand. Fuel expense increased 11.6 percent in 2004 over 2003 primarily due to an increase in the average cost of coal and natural gas. Fuel expense increased 10.1 percent in 2003 over 2002 due to an increase in generation of 3.9 percent because of higher wholesale energy demands and a 2.8 percent higher average cost of fuel due to the higher prices of coal and natural gas in 2003.

     Purchased power expense increased $194 million (19.9 percent) in 2005, $200 million (25.9 percent) in 2004, and $92 million (13.3 percent) in 2003. These increases are primarily the result of new purchased power agreements (PPAs) between the Company and Southern Power that went into effect in each of 2004, 2003, and 2002. Additional capacity expenses associated with these PPAs were $30 million, $65 million, and $75 million in 2005, 2004, and 2003, respectively. The increases in purchased power expenses also reflect the impact of the significant increases in fuel costs discussed previously.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2005 and 2004 hurricanes, result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions.

Other Operating Expenses

In 2005, other operations and maintenance expenses increased $81 million (5.8 percent). Maintenance for generating plant and transmission and distribution increased $23.5 million and $13.9 million, respectively, as a result of scheduled outages and, to a lesser extent, certain flexible projects planned for other periods. Increased employee benefit expense of $18.4 million related to pension and medical benefits and higher property insurance costs of $5.3 million resulting from storm damage also contributed to the increase. Customer

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

assistance expense and uncollectible account expense also increased an additional $9.3 million in 2005 over 2004, primarily as a result of promotional expenses related to an energy efficiency program and an increased number of customer bankruptcies, respectively. In 2004, other operations and maintenance expenses increased $153 million (12.3 percent) due to the timing of generating plant maintenance of $39 million and transmission and distribution maintenance of $39 million. Increased employee benefit expense of $30 million related to pension and medical benefits and higher workers compensation expense of $8 million also contributed to the increase. In 2003, other operations and maintenance expenses decreased $78 million (5.9 percent) due to the timing of generating plant maintenance of $46 million and transmission and distribution maintenance of $8 million and lower severance costs of $8 million.

     Depreciation and amortization increased $229 million (83 percent) in 2005 over 2004 primarily due to the expiration at the end of 2004 of certain provisions of the Company’s 2001 Retail Rate Plan. In accordance with the 2001 Retail Rate Plan, the Company amortized an accelerated cost recovery liability as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates evenly over the three years ended December 31, 2004. This treatment resulted in a credit to amortization expense of $187.1 million in 2004 and a total decrease in depreciation and amortization of $74 million and $54 million in 2004 and 2003, respectively. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.

     Taxes other than income taxes increased $32 million (14.1 percent) primarily due to higher municipal gross receipts taxes of $18.1 million resulting from increased operating revenues and higher property taxes of $14.0 million. Taxes other than income taxes increased $15 million (7.0 percent) in 2004 due to higher municipal gross receipts taxes associated with increased operating revenues. Taxes other than income taxes increased $11 million (5.4 percent) in 2003 due mainly to a favorable true-up of state property tax valuations in 2002.

Other Income and (Expense)

Allowance for equity funds used during construction remained relatively constant in 2005 and increased $15.9 million in 2004, primarily due to the construction of the McIntosh combined cycle Units 10 and 11 which were placed in service in June 2005.

     Interest income remained relatively constant in 2005. Interest income decreased $9 million in 2004 and increased $12 million in 2003 when compared to the prior year primarily due to interest on a favorable income tax settlement of $14.5 million in 2003.

     Interest expense increased $38.8 million (21.3 percent) in 2005 from 2004 primarily due to the issuance of additional senior notes in 2005 and generally higher interest rates on variable rate debt and commercial paper. Interest expense remained relatively constant in 2004. Interest expense increased in 2003 primarily due to an increase in senior notes outstanding that was partially offset by a reduction in short-term debt outstanding. The Company refinanced or retired $635 million, $400 million, and $665 million of securities in 2005, 2004, and 2003, respectively. Interest capitalized increased in 2005 and 2004 due to the Plant McIntosh construction referenced above and decreased in 2003 due to the transfer of a project to Southern Power in 2002.

     Other income and (expense), net increased $17.1 million in 2005 from 2004 primarily due to $14.2 million of additional gas hedge gains. Other income and (expense), net decreased in 2004 primarily due to the $13 million disallowance of Plant McIntosh construction costs in December 2004, partially offset by a $7.5 million decrease in donations and $3.4 million in increased income from a customer pricing program. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Hedging Program” and “Plant McIntosh Construction Project” for additional information.

Effects of Inflation

The Company is subject to rate regulation that is based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

money obligations such as long-term debt, preferred stock, and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to PPAs, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and revenues are reviewed and adjusted periodically. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” and “FERC Matters” for additional information about this and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S District Court for the Northern District of Georgia against the Company and Alabama Power, alleging that the Company and Alabama Power had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to certain coal-fired generating facilities. Through subsequent amendments and other legal proceedings, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities, including the Company’s Plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against the Company and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions.”

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and

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Georgia Power Company 2005 Annual Report

methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Georgia’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Plant Wansley Environmental Litigation

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against the Company for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of the Company in part and the plaintiffs in part. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted the Company’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

Environmental Statutes and Regulations

General

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act.

     Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $1.2 billion in

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capital projects to comply with these requirements, with annual costs of $117.4 million, $47.4 million, and $105.7 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures could exceed an additional $3.3 billion to assure compliance with existing and new regulations, including $410 million, $674.6 million, and $515.8 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $787.9 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂and NO_x emissions, maintain compliance with existing regulations, and to meet new requirements.

     Approximately $699.8 million of these expenditures are related to reducing NO_xemissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NO_x reduction rules. Although the State of Georgia was originally included in the states subject to the regional NO_x rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NO_x reduction rules for Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of the State of Georgia’s state implementation plan.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. Areas within the Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Macon (Georgia) and a 20-county area within metropolitan Atlanta. State implementation plans, including new emission control regulations necessary to bring those areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NO_x emissions from power plants.

     During 2005, the EPA’s fine particulate matter “nonattainment” designations became effective for several areas within the Company’s service area in Georgia, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO₂ and NO_x emissions from power plants. The EPA has also published proposed revisions to lower the level of particulate matter currently allowed.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks

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and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clear Air Mercury Rule on the Company, will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clear Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_{x ,}and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.

     The Company is installing cooling towers at additional facilities under the Clean Water Act to cool water prior to discharge. Near Atlanta, a cooling tower for one plant was completed in 2004 and two others are scheduled for completion in 2008. The total estimated cost of these projects is $173 million, with $85 million remaining to be spent. The Company is also conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.

     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by the State of Georgia, and therefore, cannot be determined at this time

Environmental Remediation

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

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     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account related to certain environmental insurance settlements. Under the 2004 Retail Rate Plan, this regulatory liability is being amortized as a credit to expense over a three-year period that began January 1, 2005. However, the Georgia PSC also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures are being charged against the resulting reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change, and specifically the Kyoto Protocol — which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S. – the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010-2012. The Company is continuing to evaluate future energy and emissions profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $4.9 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $10.9 million, of which $3.2 million relates to sales inside the retail service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this

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matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC also initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and Southern Company Services, Inc., as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding discussed herein under “PSC Matters – Plant McIntosh Construction Project”, be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities, with interest. The Company has opposed all such requests, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Transmission

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

PSC Matters

Merger

In connection with the Merger, the Company and Savannah Electric plan to establish a coastal regional organization for the Company that will be operating following completion of the Merger. Management expects that current Savannah Electric employees will fill most of the positions in the new regional organization.

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     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, the Company and Savannah Electric filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, the Company and Savannah Electric are seeking the approval of the Georgia PSC with respect to the following matters:

• the transfer of Savannah Electric’s generating facilities and certification of the generating facilities as the Company’s assets;

• amendments to the Company’s Integrated Resource Plan to add the current Savannah Electric’s customers and generating facilities;

• the transfer of Savannah Electric’s assigned service territory to the Company;

• adoption of the Company’s service rules and regulations to the current Savannah Electric customers;

• new fuel rate and base rate schedules that would apply to the Company’s sale of electricity to the current Savannah Electric customers;

• adoption of a “merger transition adjustment” rate that would be used to more closely align Savannah Electric’s existing base rates to those of the Company and a “merger transition credit” rate that would credit the additional revenues collected from former Savannah Electric customers to the Company’s existing customers; and

• the issuance of additional shares of the Company’s common stock to Southern Company in exchange for Southern Company’s shares of Savannah Electric common stock.

     The Company has also requested the Georgia PSC to better align the rates for Savannah Electric’s customers with those of the Company. Currently, Savannah Electric customers pay slightly lower base rates and significantly higher fuel rates than the Company’s customers. The overall effect is that Savannah Electric customers pay substantially higher overall costs for electricity. See “Fuel Cost Recovery” herein for additional information.

Rate Plans

In December 2004, the Georgia PSC approved the 2004 Retail Rate Plan for the three-year period ending December 31, 2007. Under the terms of the 2004 Retail Rate Plan, earnings are being evaluated annually against a retail return on common equity (ROE) range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates were increased by approximately $194 million and customer fees were increased by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operation and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability. In 2005 the Company recorded $2.7 million revenue subject to refund for estimated earnings above 12.25 percent retail ROE.

     The Company is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the 2004 Retail Rate Plan should be continued, modified, or discontinued. Until then, the Company will not file for a general base rate increase unless its projected retail ROE falls below 10.25 percent. However, in connection with the Merger, the Company has requested Georgia PSC approval of a “merger transition adjustment” that would be used to adjust Savannah Electric’s existing base rates to more closely match the existing base rates for the Company. See Note 3 to the financial statements under “Retail Regulatory Matters - Rate Plans” for additional information.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and the Company and Savannah Electric for capacity from Plant McIntosh Units 10 and 11, construction of which was completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, in May 2004, the Company and Savannah Electric requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities.

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Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. See “FERC Matters — Intercompany Interchange Contract” above for additional information.

     In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflected an approximate $16 million disallowance, of which $13 million was attributable to the Company, and reduced the Company’s 2004 net income by approximately $8 million. The Georgia PSC also certified a total completion cost of $547 million for the project. In June 2005, Plant McIntosh Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will be reflected in the Company’s rates evenly over the three years ending 2007. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” and “Plant McIntosh Construction Project” for additional information.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. In recent months, the Company has experienced higher than expected fuel costs for coal and natural gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets herein.

     In May 2005, the Georgia PSC approved the Company’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructed that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, the Company would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with the Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. The Company has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, the Company and Savannah Electric will file a combined request in March 2006 to increase the Company’s fuel cost recovery rate.

     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Company and Savannah Electric generating fleet as well as the under recovered fuel balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all of the Company’s customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.

     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of the Company’s fuel practices was initiated. The Company and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.

     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable cost and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow.

Nuclear

As part of a potential expansion of Plant Vogtle, the Company and Southern Nuclear have notified the Nuclear Regulatory Commission (NRC) of their intent to apply for an early site permit (ESP) this year and a combined construction and operating license (COL) in 2008. In addition, a reactor design from Westinghouse Electric Company has been selected and a purchase agreement is being negotiated. Participation agreements have been reached with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. At this point, no final decision has

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been made regarding actual construction. The NRC’s streamlined licensing process for new nuclear units allows utilities to seek regulatory approval at various stages. These stages include design certification, which is obtained by the reactor vendor, and the ESP and COL, which are each obtained by the owner-operators of the units. An ESP indicates site approval is obtained before a company decides to build and the COL provides regulatory approval for building and operating the plant. In addition, any generation by the Company must be certified by the Georgia PSC.

     Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy plans to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs, then to choose one of the applications and file it for NRC review and approval. The COL ultimately is expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.

Other Matters

In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pension income, before tax, of approximately $21 million, $35 million, and $54 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $47 million, $44 million, and $41 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. For the Company, pension income or expense and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

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

     As reflected in Note 1 to the financial statements under “Regulatory Assets and Liabilities,” significant regulatory assets and liabilities have been recorded.

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Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

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

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

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

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

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

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

Unbilled Revenues

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

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47, Conditional Asset Retirement Obligations (FIN 47), which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”

     At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $91 million. The adoption of FIN 47 did not have any effect on the Company’s income statement.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

Stock Options

On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be stable at December 31, 2005 with emphasis on cost control measures combined with significantly lower costs of capital, achieved through the refinancing and/or redemption of higher-cost securities. Cash flow from operations increased $56 million resulting primarily from increased retail operating revenues (see RESULTS OF OPERATIONS herein), partially offset by the increase in under recovered deferred fuel costs.

     Fuel costs are generally recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.

     In 2005, gross utility plant additions were $906 million. These additions were primarily related to Plant McIntosh Units 10 and 11, transmission and distribution facilities, nuclear fuel, and equipment to comply with environmental standards. The majority of funds needed for gross property additions for the last several years have been provided from operating activities and capital contributions from Southern Company. The statements of cash flows provide additional details.

     The Company’s ratio of common equity to total capitalization — including short-term debt — was 48.3 percent in 2005, 47.7 percent in 2004, and 48.3 percent in 2003. The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.

     The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by the Company is subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended, on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

     The Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business.

     To meet short-term cash needs and contingencies, the Company had credit arrangements with banks totaling $780 million, of which $778 million was unused, at the beginning of 2006. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other retail operating companies.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefits of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. As of December 31, 2005, the Company had outstanding $268 million of commercial paper and no extendible commercial notes.

     At the beginning of 2006, bank credit arrangements were as follows:

			Expires
Total	Unused		2006		2007		2010
			(in millions)
$780	$	778	$	70	$	350	$	360

     The credit arrangements that expire in 2006 allow for the execution of term loans for an additional two-year period.

Financing Activities

During 2005, the Company issued $810 million of long-term debt. The issuances were used to refund $635 million of long-term debt and to fund the Company’s ongoing construction program.

     Subsequent to December 31, 2005, the Company redeemed all of its outstanding preferred stock at a redemption price of $107 per share.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $6 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $245 million.

     The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, the Company had no material exposure related to these agreements.

Market Price Risk

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

     To mitigate future exposure to changes in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. These swaps have a notional amount of $300 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on outstanding variable long-term debt that has not been hedged at January 1, 2006 was 3.56 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $3.3 million at January 1, 2006. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

     To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases.

     The Company has implemented a fuel hedging program at the instruction of the Georgia PSC. Fair

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

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

	Changes in Fair Value
	2005			2004
	(in millions)
Contracts beginning of year	$	5.8		$	3.2
Contracts realized or settled		(40.0	)		(12.2	)
Current period changes (a)		60.8			14.8
Contracts end of year	$	26.6		$	5.8

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

	Source of 2005 Year-End Valuation Prices
	Total			Maturity
	Fair Value			Year 1			1-3 Years
	(in millions)
Actively quoted	$	26.8		$	16.4		$	10.4
External sources		(0.2	)		(0.2	)		—
Contracts end of year	$	26.6		$	16.2		$	10.4

     Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery mechanism. Of the net gains, the Company is allowed to retain 25 percent in earnings. In 2005, the Company had a total net gain of $64.1 million, of which the Company retained $16.0 million. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Hedging Program” for additional information. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in millions)
Regulatory liabilities, net	$	26.7
Net income		(0.1	)
Total fair value	$	26.6

     Unrealized gains (losses) recognized in income in 2005, 2004, and 2003 were not material. The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $1.3 billion for 2006, $1.4 billion for 2007, and $1.3 billion for 2008. Environmental expenditures included in these amounts are $410 million, $674.6 million, and $515.8 million for 2006, 2007, and 2008, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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

     In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

     Amounts in the following chart exclude any effects on the Company of the Merger.

Contractual Obligations

			2007-		2009-		After
	2006		2008		2010		2010		Total
					(in millions)
Long-term debt(a) —
Principal	$	153	$	306	$	282	$	4,563	$	5,304
Interest		265		496		468		4,989		6,218
Preferred stock		15		—		—		—		15
Commodity derivative obligations(b)		12		—		—		—		12
Operating leases		34		58		44		58		194
Purchase commitments(c) —
Capital(d)		1,251		2,738		2,421		—		6,410
Coal		1,579		2,220		694		40		4,533
Nuclear fuel		44		42		25		64		175
Natural gas(e)		577		525		511		2,047		3,660
Purchased power		343		689		559		994		2,585
Long-term service agreements		7		18		24		144		193
Trusts(f) —
Nuclear decommissioning		7		14		14		117		152
Postretirement benefits		18		41		—		—		59
DOE assessments		4		—		—		—		4
Total	$	4,309	$	7,147	$	5,042	$	13,016	$	29,514

(a)	All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest risk.
(b)	For additional information see Notes 1 and 6 to the financial statements herein.
(c)	The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $1.5 billion, $1.4 billion, and $1.2 billion, respectively.
(d)	The Company forecasts capital expenditures over a five-year period. Amounts represent current estimates of total expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(e)	Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(f)	Projections of nuclear decommissioning trust contributions are based on the 2004 Retail Rate Plan. The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, storm cost recovery and repairs, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and the Company, the impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will”, “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and implementation of the Energy Policy Act of 2005, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and the pending EPA civil action against the Company;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

• other factors discussed elsewhere herein and in other reports, including the Form 10-K, filed by the Company from time to time with the Securities and Exchange Commission.

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

II-151

STATEMENTS OF INCOME

For the Years Ended December 31, 2005, 2004, and 2003

Georgia Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Revenues:
Retail sales	$	5,642,812		$	4,776,985		$	4,309,972
Sales for resale—
Non-affiliates		519,673			246,545			259,376
Affiliates		264,989			166,245			174,855
Other revenues		206,729			181,033			169,304
Total operating revenues		6,634,203			5,370,808			4,913,507
Operating Expenses:
Fuel		1,830,829			1,232,496			1,103,963
Purchased power—
Non-affiliates		408,563			304,978			258,621
Affiliates		761,466			671,098			516,944
Other operations		949,722			902,167			827,972
Maintenance		531,168			498,114			419,206
Depreciation and amortization		504,248			275,488			349,984
Taxes other than income taxes		259,825			227,806			212,827
Total operating expenses		5,245,821			4,112,147			3,689,517
Operating Income		1,388,382			1,258,661			1,223,990
Other Income and (Expense):
Allowance for equity funds used during construction		26,808			26,659			10,752
Interest income		6,281			6,657			15,625
Interest expense, net of amounts capitalized		(221,199	)		(182,370	)		(182,583	)
Interest expense to affiliate trusts		(59,510	)		(44,565	)		—
Distributions on mandatorily redeemable preferred securities		—			(15,839	)		(59,675	)
Other income (expense), net		5,742			(11,362	)		(10,551	)
Total other income and (expense)		(241,878	)		(220,820	)		(226,432	)
Earnings Before Income Taxes		1,146,504			1,037,841			997,558
Income taxes		430,812			379,170			366,311
Net Income		715,692			658,671			631,247
Dividends on Preferred Stock		693			670			670
Net Income After Dividends on Preferred Stock	$	714,999		$	658,001		$	630,577

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

II-152

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005, 2004, and 2003

Georgia Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Activities:
Net income	$	715,692		$	658,671		$	631,247
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		592,264			361,958			424,321
Deferred income taxes and investment tax credits, net		231,708			251,623			199,265
Deferred expenses - affiliates		1,268			(10,563	)		(7,399	)
Allowance for equity funds used during construction		(26,808	)		(26,659	)		(10,752	)
Pension, postretirement, and other employee benefits		(19,468	)		(15,868	)		(30,225	)
Tax benefit of stock options		15,711			9,701			11,649
Other, net		(11,068	)		(19,764	)		18,929
Changes in certain current assets and liabilities —
Receivables		(591,498	)		(227,204	)		(4,395	)
Fossil fuel stock		2,528			(46,730	)		(17,490	)
Materials and supplies		(53,942	)		618			(7,677	)
Prepaid income taxes		(43,626	)		14,358			(3,951	)
Other current assets		4,108			(23,672	)		1,599
Accounts payable		110,118			132,001			(62,553	)
Accrued taxes		85,098			(64,563	)		52,348
Accrued compensation		3,822			(6,664	)		(3,111	)
Other current liabilities		33,289			5,836			19,845
Net cash provided from operating activities		1,049,196			993,079			1,211,650
Investing Activities:
Property additions		(842,870	)		(741,151	)		(717,993	)
Nuclear decommissioning trust fund purchases		(381,235	)		(541,048	)		(656,806	)
Nuclear decommissioning trust fund sales		372,536			532,349			648,107
Purchase of property from affiliates		—			(339,750	)		(2	)
Cost of removal net of salvage		(29,428	)		(21,756	)		(28,265	)
Change in construction payables, net of joint owner portion		4,037			413			(32,223	)
Other		(315	)		(4,961	)		1,008
Net cash used for investing activities		(877,275	)		(1,115,904	)		(786,174	)
Financing Activities:
Increase (decrease) in notes payable, net		59,509			70,956			(220,400	)
Proceeds—
Senior notes		625,000			600,000			1,000,000
Pollution control bonds		185,000			—			—
Mandatorily redeemable preferred securities		—			200,000			—
Capital contributions from parent company		149,034			260,068			40,809
Redemptions—
Pollution control bonds		(185,000	)		—			—
Senior notes		(450,000	)		(200,000	)		(665,000	)
Mandatorily redeemable preferred securities		—			(200,000	)		—
Payment of preferred stock dividends		(546	)		(654	)		(696	)
Payment of common stock dividends		(556,100	)		(565,500	)		(565,800	)
Other		(21,679	)		(17,247	)		(22,563	)
Net cash provided from (used for) financing activities		(194,782	)		147,623			(433,650	)
Net Change in Cash and Cash Equivalents		(22,861	)		24,798			(8,174	)
Cash and Cash Equivalents at Beginning of Year		33,497			8,699			16,873
Cash and Cash Equivalents at End of Year	$	10,636		$	33,497		$	8,699
Supplemental Cash Flow Information:
Cash paid during the period for—
Interest (net of $10,871, $8,920, and $5,428 capitalized, respectively)	$	250,445		$	228,190		$	215,463
Income taxes (net of refunds)		207,973			127,115			145,048

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

II-153

BALANCE SHEETS

At December 31, 2005 and 2004

Georgia Power Company 2005 Annual Report

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

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

II-154

BALANCE SHEETS
At December 31, 2005 and 2004
Georgia Power Company 2005 Annual Report

Liabilities and Stockholder’s Equity	2005		2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	167,317	$	452,498
Notes payable		267,743		208,233
Accounts payable —
Affiliated		285,019		194,253
Other		360,455		310,763
Customer deposits		129,293		115,661
Accrued taxes —
Income taxes		150,896		78,269
Other		204,778		129,520
Accrued interest		88,885		74,529
Accrued vacation pay		45,602		44,894
Accrued compensation		137,303		127,340
Other		120,312		83,632
Total current liabilities		1,957,603		1,819,592
Long-term Debt(See accompanying statements)		4,179,218		3,709,852
Long-term Debt Payable to Affiliated Trusts(See accompanying statements)		969,073		969,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,730,303		2,556,040
Deferred credits related to income taxes		158,759		170,973
Accumulated deferred investment tax credits		287,726		300,018
Employee benefit obligations		358,137		331,002
Asset retirement obligations		627,465		504,515
Other cost of removal obligations		404,614		411,692
Other regulatory liabilities		97,015		84,678
Other		63,335		59,733
Total deferred credits and other liabilities		4,727,354		4,418,651
Total Liabilities		11,833,248		10,917,168
Preferred Stock(See accompanying statements)		—		14,609
Common Stockholder’s Equity(See accompanying statements)		5,214,535		4,890,561
Total Liabilities and Stockholder’s Equity	$	17,047,783	$	15,822,338
Commitments and Contingent Matters(See notes)

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

II-155

STATEMENTS OF CAPITALIZATION

At December 31, 2005 and 2004
Georgia Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long-Term Debt:
Long-term notes payable —
5.50% due December 1, 2005	$	—		$	150,000
Variable rate (1.66% to 1.96% at 1/1/05) due 2005		—			300,000
6.20% due February 1, 2006		150,000			150,000
4.875% due July 15, 2007		300,000			300,000
4.10% due August 15, 2009		125,000			125,000
Variable rate (4.53% at 1/1/06) due 2009		150,000			150,000
4.00% to 6.00% due 2011-2045		1,850,000			1,225,000
Total long-term notes payable		2,575,000			2,400,000
Other long-term debt —
Pollution control revenue bonds — non-collateralized:
2.83% to 5.45% due 2012-2034		812,560			812,560
Variable rate (2.82% to 3.08% at 1/1/06) due 2011-2032		873,330			873,330
Total other long-term debt		1,685,890			1,685,890
Capitalized lease obligations		74,484			76,982
Unamortized debt premium (discount), net		(3,448	)		(522	)
Total long-term debt (annual interest requirement — $205.5 million)		4,331,926			4,162,350
Less amount due within one year		152,708			452,498
Long-term debt excluding amount due within one year		4,179,218			3,709,852			40.3	%		38.7	%
Long-term Debt Payable to Affiliated Trusts:
4.88% to 7.13% due 2042 (annual interest requirement — $59.5 million)		969,073			969,073			9.4			10.1
Cumulative Preferred Stock:
$100 stated value at 4.60%
Authorized — 5,000,000 shares
Outstanding — 145,689 shares (annual dividend requirement — $0.7 million)		14,609			14,609
Less amount due within one year		14,609			—
Total cumulative preferred stock excluding amount due within one year		—			14,609			0.0			0.2
Common Stockholder’s Equity:
Common stock, without par value —
Authorized — 15,000,000 shares
Outstanding — 7,761,500 shares		344,250			344,250
Paid-in capital		2,643,012			2,478,268
Retained earnings		2,261,698			2,102,798
Accumulated other comprehensive income (loss)		(34,425	)		(34,755	)
Total common stockholder’s equity		5,214,535			4,890,561			50.3			51.0
Total Capitalization	$	10,362,826		$	9,584,095			100.0	%		100.0	%

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

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

For the Years Ended December 31, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
						(in thousands)
Balance at December 31, 2002	$	344,250	$	2,156,080		$	1,945,520		$	(11,403	)	$	4,434,447
Net income after dividends on preferred stock		—		—			630,577			—			630,577
Capital contributions from parent company		—		52,458			—			—			52,458
Other comprehensive income (loss)		—		—			—			(11,471	)		(11,471	)
Cash dividends on common stock		—		—			(565,800	)		—			(565,800	)
Balance at December 31, 2003		344,250		2,208,538			2,010,297			(22,874	)		4,540,211
Net income after dividends on preferred stock		—		—			658,001			—			658,001
Capital contributions from parent company		—		269,769			—			—			269,769
Other comprehensive income (loss)		—		—			—			(11,881	)		(11,881	)
Cash dividends on common stock		—		—			(565,500	)		—			(565,500	)
Other		—		(39	)		—			—			(39	)
Balance at December 31, 2004		344,250		2,478,268			2,102,798			(34,755	)		4,890,561
Net income after dividends on preferred stock		—		—			714,999			—			714,999
Capital contributions from parent company		—		164,745			—			—			164,745
Other comprehensive income (loss)		—		—			—			330			330
Cash dividends on common stock		—		—			(556,100	)		—			(556,100	)
Other		—		(1	)		1			—			—
Balance at December 31, 2005	$	344,250	$	2,643,012		$	2,261,698		$	(34,425	)	$	5,214,535

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

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2005, 2004, and 2003
Georgia Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Net income after dividends on preferred stock	$	714,999		$	658,001		$	630,577
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(1,981), $(3,861) and $(5,133), respectively		(3,140	)		(6,122	)		(8,138	)
Change in fair value of marketable securities, net of tax of $317 and $(114)		501			(181	)		—
Changes in fair value of qualifying hedges, net of tax of $1,214, $(5,046) and $(3,241), respectively		1,925			(7,999	)		(5,550	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $848, $1,528 and $1,208, respectively		1,044			2,421			2,217
Total other comprehensive income (loss)		330			(11,881	)		(11,471	)
Comprehensive Income	$	715,329		$	646,120		$	619,106

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

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Georgia Power Company 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Georgia Power Company (Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies — Alabama Power, the Company, Gulf Power, Mississippi Power, and Savannah Electric — provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power — related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC). SCS — the system service company — provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. In January 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

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

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is subject to regulation by the FERC and the Georgia Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $330 million in 2005, $292 million in 2004, and $303 million in 2003. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the PUHCA and management believes they are reasonable.

     The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, and systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $328 million in 2005, $311 million in 2004, and $289 million in 2003.

     The Company has an agreement with Southern Power under which the Company operates and maintains Southern Power owned plants Dahlberg, Franklin, and Wansley at cost. Billings under these agreements with Southern Power amounted to $5.2 million in 2005, $4.8 million in 2004, and $5.3 million in 2003.

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     The Company has an agreement with SouthernLINC Wireless under which the Company receives digital wireless communications services and purchases digital equipment. Costs for these services amounted to $7.3 million in 2005, $7.7 million in 2004, and $7.4 million in 2003.

     Southern Company holds a 30 percent ownership in Alabama Fuel Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement with an indirect subsidiary of Southern Company that provides services for AFP. Under this agreement, the Company provides certain accounting functions, including processing and paying fuel transportation invoices, and the Company is reimbursed for its expenses. Amounts billed under this agreement totaled approximately $61 million in 2005, $53 million in 2004, and $38 million in 2003. In addition, the Company purchases synthetic fuel from AFP for use at plants Branch, McDonough, and Bowen. Fuel purchases totaled $216 million in 2005, $163 million in 2004, and $91 million in 2003.

     The Company has entered into several purchased power agreements (PPAs) with Southern Power for capacity and energy. Expenses associated with these PPAs were $419 million, $282 million, and $203 million in 2005, 2004, and 2003, respectively. Additionally, the Company recorded a reduction of $1 million and an increase of $11 million of prepaid capacity expenses included on the balance sheets at December 31, 2005 and 2004, respectively. See Note 7 under “Purchased Power Commitments” for additional information.

     The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer. Under this agreement, the Company operates Plant Scherer, and Gulf Power reimburses the Company for its proportionate share of the related expenses which were $4.3 million in 2005, $6.8 million in 2004, and $4.9 million in 2003. The Company has an agreement with Savannah Electric under which the Company jointly owns a portion of Plant McIntosh. Under this agreement, Savannah Electric operates Plant McIntosh, and the Company reimburses Savannah Electric for its proportionate share of the related expenses which were $5.5 million in 2005, $3.3 million in 2004, and $3.7 million in 2003. See Note 4 for additional information.

     The Company provides incidental services to other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in the last two years, assistance provided to aid in storm restoration, including company labor, contract labor, and materials, has caused an increase in these activities. The total amount of storm assistance provided to Alabama Power, Gulf Power, and Mississippi Power in 2005 was $4.1 million, $4.4 million, and $55 million, respectively. The total amount of storm assistance provided to Alabama Power and Gulf Power in 2004 was $4.1 million and $6.4 million, respectively. These activities were billed at cost.

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

     The retail operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.

     The Company has entered into an agreement to merge with Savannah Electric. See Note 3 under “Retail Regulatory Matters – Merger” for additional information.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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Georgia Power Company 2005 Annual Report

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

	2005			2004			Note
	(in millions)
Deferred income tax charges	$	501		$	506			(a	)
Premium on reacquired debt		170			177			(b	)
Corporate building lease		52			53			(e	)
Vacation pay		59			57			(d	)
Postretirement benefits		18			20			(e	)
DOE assessments		6			10			(c	)
Generating plant outage costs		46			40			(g	)
Other regulatory assets		33			11			(e	)
Asset retirement obligation		65			(20	)		(a	)
Other cost of removal obligations		(404	)		(412	)		(a	)
Deferred income tax credits		(159	)		(171	)		(a	)
Environmental remediation		(19	)		(22	)		(f	)
Purchased power		(33	)		—			(f	)
Other regulatory liabilities		(30	)		(6	)		(e	)
Total	$	305		$	243

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

(a)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 60 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years.
(c)	Assessments for the decontamination and decommissioning of the DOE’s nuclear fuel enrichment facilities are recorded annually from 1993 through 2006.
(d)	Recorded as earned by employees and recovered as paid, generally within one year.
(e)	Recorded and recovered or amortized as approved by the Georgia PSC.
(f)	Amortized over a three-year period ending in 2007. See Note 3 under “Retail Regulatory Matters — Rate Plans.”
(g)	See “Property, Plant, and Equipment” herein.

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

Revenues

Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.

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

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $70 million in 2005, $73 million in 2004, and $74 million in 2003.

Nuclear Fuel Disposal Costs

The Company has contracts with the U.S. Department of Energy (DOE) that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plant Hatch, an on-site dry storage facility is operational and can be expanded to accommodate spent fuel through the life of the plant.

     Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment has been paid over a 15-

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Georgia Power Company 2005 Annual Report

year period; the final installment is scheduled to occur in 2006. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company, based on its ownership interest, estimates its remaining liability at December 31, 2005 under this law to be approximately $4 million.

Income Taxes

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

Manufacturer’s Tax Credits

The State of Georgia provides a tax credit for qualified investment property to manufacturing companies that construct new facilities. The credit ranges from 1 percent to 8 percent of qualified construction expenditures depending upon the county in which the new facility is located. The Company’s policy is to recognize these credits when management believes that they are more likely than not to be allowed by the Georgia Department of Revenue. Manufacturer’s tax credits of $12.5 million, $12.9 million, and $12.0 million were recorded in 2005, 2004, and 2003, respectively.

Property, Plant, and Equipment

The Company’s property, plant, and equipment consisted of the following at December 31 (in millions):

	2005		2004
Generation	$	9,571	$	9,002
Transmission		2,994		2,870
Distribution		5,953		5,744
General		1,057		1,038
Plant acquisition adjustment		28		28
Total plant in service	$	19,603	$	18,682

     Property, plant, and equipment is stated at original cost, less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction.

     The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling costs over the unit’s operating cycle before the next refueling. The refueling cycles are 18 and 24 months for plants Vogtle and Hatch, respectively. In accordance with the Georgia PSC rate order, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 2.6 percent in 2005, 2.6 percent in 2004, and 2.7 percent in 2003. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. In connection with the new retail rate plan for the Company ending December 31, 2007 (2004 Retail Rate Plan), effective January 1, 2005, the depreciation rates were revised by the Georgia PSC. The revised depreciation rates had no material impact on the Company’s financial statements.

     When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

     Under the three-year retail rate plan for the Company ending December 31, 2004 (2001 Retail Rate Plan), the Company discontinued recording accelerated depreciation and amortization. Also, the Company was ordered to amortize $333 million, the cumulative balance previously expensed, equally over three years as a credit to amortization expense beginning January

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Georgia Power Company 2005 Annual Report

2002. Additionally, the Company was ordered to recognize new Georgia PSC certified purchased power costs in rates evenly over the three years covered by the 2001 Retail Rate Plan. As a result of the purchased power regulatory adjustment, the Company recorded amortization expenses of $14 million in 2003. The Company recorded a credit to amortization expense of $77 million in 2004. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations (FIN 47), which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of their retirements was dependent on future events. The Company has received approval from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected on the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or FIN 47.

     The liability recognized to retire long-lived assets primarily relates to the Company’s nuclear facilities, which include the Company’s ownership interests in plants Hatch and Vogtle. The fair value of assets legally restricted for settling retirement obligations related to nuclear facilities as of December 31, 2005 was $487 million. In addition, the Company has recognized retirement obligations related to various landfill sites, ash ponds, and underground storage tanks. The Company also recorded additional asset retirement obligations (and assets) of approximately $91 million related to asbestos removal. The Company has also identified retirement obligations related to certain transmission and distribution facilities, leasehold improvements, equipment on customer property, and property associated with the Company’s rail lines. However, liabilities for the removal of these assets have not been recorded because no reasonable estimate can be made regarding the timing of any related retirements. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and FIN 47 and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

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

	2005			2004
	(in millions)
Balance beginning of year	$	505		$	476
Liabilities incurred		91			—
Liabilities settled		(2	)		(2	)
Accretion		33			31
Balance end of year	$	627		$	505

     If FIN 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $591 million.

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds to comply with the NRC’s regulations. Use of the funds is restricted to nuclear decommissioning activities and the funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The trust funds are invested in a tax- 

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Georgia Power Company 2005 Annual Report

efficient manner in a diversified mix of equity and fixed income securities and are classified as available-for-sale. The trust funds are included in the balance sheets at fair value, as obtained from quoted market prices for the same or similar investments. Details of the securities held in these trusts at December 31 are as follows:

	Unrealized		Unrealized			Fair
2005	Gains		Losses			Value
	(in millions)
Equity	$	76.7	$	(6.3	)	$	325.5
Debt		2.8		(0.8	)		135.3
Other		—		—			25.8
Total	$	79.5	$	(7.1	)	$	486.6

	Unrealized		Unrealized			Fair
2004	Gains		Losses			Value
	(in millions)
Equity	$	68.7	$	(4.0	)	$	308.2
Debt		5.3		(0.1	)		138.0
Other		—		—			13.0
Total	$	74.0	$	(4.1	)	$	459.2

     The contractual maturities of debt securities at December 31, 2005 are as follows: $3.2 million in 2006; $34.9 million in 2007-2010; $32.4 million in 2011-2015; and $57.2 million thereafter.

     Sales of the securities held in the trust funds resulted in proceeds of $372.5 million, $532.3 million, and $648.1 million in 2005, 2004, and 2003, respectively, all of which were re-invested. Net realized gains (losses) were $12.6 million, $14.1 million, and $21.3 million in 2005, 2004, and 2003, respectively. Realized gains and losses are determined on a specific identification basis. In accordance with regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive income. Unrealized gains and losses are considered non-cash transactions for purposes of the statements of cash flow. Unrealized losses were not material in any period presented and do not represent any impairment of the underlying investments.

     Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Georgia PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that, over time — the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Georgia PSC. The amount expensed in 2005 and fund balances were as follows:

	Plant		Plant
	Hatch		Vogtle
	(in millions)
Amount expensed in 2005	$	—	$	7
Accumulated provisions:
External trust funds, at fair value	$	313	$	174
Internal reserves		—		1
Total	$	313	$	175

     Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning based on the most current study performed in 2003 for the Company’s ownership interests in plants Hatch and Vogtle were as follows:

	Plant		Plant
	Hatch		Vogtle
Decommissioning periods:
Beginning year	2034		2027
Completion year	2065		2048
	(in millions)
Site study costs:
Radiated structures	$	497	$	452
Non-radiated structures		49		58
Total	$	546	$	510

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

     Under the 2001 Retail Rate Plan, the Georgia PSC approved the annual decommissioning costs for ratemaking of $9 million. This amount was based on the NRC generic estimate to decommission the radioactive

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portion of the facilities as of 2000. The estimates were $383 million and $282 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking included an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent.

     Under the 2004 Retail Rate Plan, effective January 1, 2005, the Georgia PSC decreased the annual decommissioning costs for ratemaking to $7 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2003. The estimates are $421 million and $326 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 3.1 percent and an estimated trust earnings rate of 5.1 percent. Another significant assumption used was the change in the operating license for Plant Hatch. In January 2002, the NRC granted the Company a 20-year extension of the licenses for both units at Plant Hatch which permits the operation of units 1 and 2 until 2034 and 2038, respectively. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.

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

In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. Interest related to the construction of new facilities not included in the Company’s retail rates is capitalized in accordance with standard interest capitalization requirements. For the years 2005, 2004, and 2003, the average AFUDC rates were 8.02 percent, 8.22 percent, and 5.51 percent, respectively. AFUDC and interest capitalized, net of taxes, were 4.7 percent and 4.9 percent of net income after dividends on preferred stock for 2005 and 2004, respectively, and less than 3 percent for 2003.

Impairment of Long-Lived Assets and Intangibles

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

Storm Damage Reserve

The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. The Company accrues $6.3 million annually that is recoverable through base rates. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.

Environmental Cost Recovery

Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account related to certain environmental insurance settlements. Under the 2004 Retail Rate Plan, this regulatory liability is being amortized over a three-year period beginning January 1, 2005. However, the Georgia PSC also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures are charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

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Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income-tax benefit.

     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date.

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

	As		Options			Pro
Net Income	Reported		Impact			Forma
	(in millions)
2005	$	715	$	(3	)	$	712
2004	$	658		(3	)	$	655
2003	$	631		(4	)	$	627

     The estimated fair value of stock options granted in 2005, 2004, and 2003 was derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options.

	2005			2004			2003
Interest rate		3.90	%		3.10	%		2.70	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.90	%		19.60	%		23.60	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

     See Note 8 for additional information.

Financial Instruments

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

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through current period income and are recorded on a net basis in the statements of income.

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

     The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:

	Carrying		Fair
	Amount		Value
	(in millions)
Long-term debt:
2005	$	5,227	$	5,195
2004	$	5,055	$	5,125

     The fair values were based on either closing market prices or closing prices of comparable instruments.

Comprehensive Income

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

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-Term Debt Payable to Affiliated Trusts on the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds related trusts to the extent required by the Georgia PSC and the FERC. For the year ended December 31, 2006, such contributions are expected to total approximately $18.4 million. The measurement date for plan assets and obligations is September 30 for each year presented.

Pension Plans

The accumulated benefit obligation for the pension plans was $1.9 billion in 2005 and $1.7 billion in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and the fair
value of plan assets was as follows:

Projected Benefit Obligation
	2005			2004
	(in millions)
Balance at beginning of year	$	1,885		$	1,727
Service cost		45			42
Interest cost		106			101
Benefits paid		(85	)		(85	)
Plan amendments		13			1
Actuarial loss		91			99
Balance at end of year	$	2,055		$	1,885

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	2,181		$	2,055
Actual return on plan assets		339			207
Benefits paid		(80	)		(81	)
Balance at end of year	$	2,440		$	2,181

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     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $1.945 billion and $110 million, respectively. All plan assets are related to the qualified plan.

Pension plan assets are managed and invested in accordance with all applicable requirements including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes.

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

	Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	385		$	295
Unrecognized transition amount		(4	)		(8	)
Unrecognized prior service cost		109			108
Unrecognized net actuarial gain (loss)		(54	)		21
Prepaid pension asset, net	$	436		$	416

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

	2005			2004
	(in millions)
Prepaid pension asset	$	476		$	450
Employee benefit obligations		(96	)		(89	)
Other property and investments		15			19
Accumulated other comprehensive income		41			36
Prepaid pension asset, net	$	436		$	416

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

	2005			2004			2003
	(in millions)
Service cost	$	45		$	42		$	38
Interest cost		106			101			100
Expected return on plan assets		(182	)		(180	)		(179	)
Recognized net (gain)/loss		3			(5	)		(19	)
Net amortization		7			7			6
Net pension (income)	$	(21	)	$	(35	)	$	(54	)

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	Benefit
	Payments
	(in millions)
2006	$	88
2007		91
2008		94
2009		97
2010		102
2011 to 2015	$	607

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Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

	Accumulated
	Benefit Obligation
	2005			2004
	(in millions)
Balance at beginning of year	$	726		$	723
Service cost		10			10
Interest cost		41			41
Benefits paid		(32	)		(31	)
Actuarial loss		24			42
Plan amendments		—			(59	)
Balance at end of year	$	769		$	726

	Plan Assets
	2005			2004
	(in millions)
Balance at beginning of year	$	299		$	265
Actual return on plan assets		38			32
Employer contributions		40			33
Benefits paid		(32	)		(31	)
Balance at end of year	$	345		$	299

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification, but also monitors and manages other aspects of risk.

	Plan Assets
	Target			2005			2004
Domestic equity		43	%		43	%		42	%
International equity		21			22			23
Domestic fixed income		19			19			19
Global fixed income		11			11			11
Real estate		4			3			3
Private equity		2			2			2
Total		100	%		100	%		100	%

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

	2005			2004
	(in millions)
Funded status	$	(424	)	$	(428	)
Unrecognized transition obligation		70			78
Unrecognized prior service cost		25			27
Unrecognized net loss		203			203
Fourth quarter contributions		21			15
Employee benefit obligations recognized in the balance sheets	$	(105	)	$	(105	)

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

	2005			2004			2003
	(in millions)
Service cost	$	10		$	10		$	9
Interest cost		41			41			40
Expected return on plan assets		(22	)		(25	)		(24	)
Net amortization		18			18			16
Net postretirement cost	$	47		$	44		$	41

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP)106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $5 million and $10 million, respectively, and is expected to have a similar impact on future expenses.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug

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Georgia Power Company 2005 Annual Report

subsidy receipts expected as a result of the Medicare Act as follows:

	Benefit		Subsidy
	Payments		Receipts			Total
	(in millions)
2006	$	37	$	(3	)	$	34
2007		39		(4	)		35
2008		42		(4	)		38
2009		46		(4	)		42
2010		50		(5	)		45
2011 to 2015		280		(34	)		246

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were:

	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00			3.50			3.75
Long-term return on plan assets		8.50			8.50			8.50

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005, as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	70	$	62
Service and interest costs		5		4

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for the years 2005, 2004, and 2003 were $19 million, $18 million, and $18 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S District Court for the Northern District of Georgia against the Company and Alabama Power, alleging that the Company and Alabama Power had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to certain coal-fired generating facilities. Through subsequent amendments and other legal proceedings, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power after it was dismissed from the original action. In these lawsuits, the

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EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against the Company and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this case could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

Plant Wansley Environmental Litigation

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against the Company for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of the Company in part and the plaintiffs in part. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted the Company’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

Environmental Remediation

The Company has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act. In 1995, the EPA designated the Company and four other unrelated entities as potentially responsible parties at a site in Brunswick, Georgia that is listed on the federal National Priorities List. As of December 31, 2005, the Company had recorded approximately $6 million in cumulative expenses associated with the Company’s agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. Additional claims for recovery of natural resource damages at the site are anticipated. The Company has also recognized $36 million in cumulative expenses through December 31, 2005 for the assessment and anticipated cleanup of sites on the Georgia Hazardous Sites Inventory.

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

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

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     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC agreed to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $4.9 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $10.9 million, of which $3.2 million relates to sales inside the retail service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC also initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding involving an approval of PPAs between Southern Power and the Company and Savannah Electric, be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the

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transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with the Company and another Southern Company subsidiary, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities, with interest. The Company has opposed such relief and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Race Discrimination Litigation

In July 2000, a lawsuit alleging race discrimination was filed by three of the Company’s employees against the Company, Southern Company, and SCS in the Superior Court of Fulton County, Georgia. Shortly thereafter, the lawsuit was removed to the U.S. District Court for the Northern District of Georgia and amended to add four more plaintiffs. The lawsuit also raised claims on behalf of a purported class. The plaintiffs sought compensatory and punitive damages in an unspecified amount, as well as injunctive relief.

     Following various court decisions in favor of the defendants and subsequent appeals by the plaintiffs, on July 13, 2005, the plaintiffs filed a petition for writ of certiorari to the U.S. Supreme Court. On October 17, 2005, the petition was denied. This matter is now concluded.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including the Company, Gulf Power, Mississippi Power, and Southern Telecom, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief. Management believes that the Company has complied with applicable laws and that the plaintiffs’ claims are without merit.

     In January 2005, the Superior Court of Decatur County, Georgia granted partial summary judgment in a lawsuit brought by landowners against the Company based on the plaintiffs’ declaratory judgment claim that the easements do not permit general telecommunications use. The Company appealed this ruling to the Georgia Court of Appeals. The Georgia Court of Appeals reversed, in part, the court’s order and remanded the case to the trial court for the determination of further issues. After the Court of Appeals’ decision, the plaintiffs filed a motion for reconsideration, which was denied, and a petition for certiorari to the Georgia Supreme Court, which is currently pending. The question of damages and other liabilities or remedies issues with respect to this action, if any, will be decided at a future trial. In the event of an adverse verdict in the case, the Company could appeal both liability and damages or other relief granted. An adverse outcome in these matters could result in substantial judgments; however, the final outcome cannot now be determined.

     In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom, were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

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Property Tax Dispute

The Company is involved in a significant property tax dispute with Monroe County, Georgia (Monroe County). The Monroe County Board of Tax Assessors (Monroe Board) has issued assessments reflecting substantial increases in the ad valorem tax valuation of the Company’s 22.95 percent ownership interest in Plant Scherer, which is located in Monroe County, for tax years 2003, 2004, and 2005. The Company is aggressively pursuing administrative appeals in Monroe County and has filed notices of arbitration for all three years. The appeals are currently stayed, pending the outcome of the litigation discussed below.

     In November 2004, the Company filed suit, on its behalf, against the Monroe Board in the Superior Court of Monroe County. The Company contends that Monroe County acted without statutory authority in changing the valuation of a centrally assessed utility as established by the Revenue Commissioner of the State of Georgia and requests injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from the Company. On December 22, 2005, the court granted Monroe County’s motion for summary judgment. The Company has filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.

     If the Company is not successful in its administrative appeals and if Monroe County is successful in defending the litigation, the Company could be subject to total additional taxes through December 31, 2005 of up to $13 million, plus penalties and interest. The ultimate outcome of this matter cannot currently be determined.

Retail Regulatory Matters

Merger

On December 13, 2005, the Company and Savannah Electric entered into an Agreement and Plan of Merger. Savannah Electric will merge into the Company, with the Company continuing as the surviving corporation (the Merger). At the effective time of the Merger, each share of the Company’s common stock will remain issued and outstanding; each share of the Company’s preferred stock issued and outstanding will have been redeemed prior to the Merger; the issued and outstanding shares of Savannah Electric common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of the Company’s common stock; and each share of Savannah Electric preferred stock issued and outstanding immediately prior to the Merger will be converted into the right to receive one share of a new series of the Company’s Class A Preferred Stock. The Merger must be approved by the preferred shareholders of Savannah Electric and is subject to the receipt of certain regulatory approvals from the FERC, the Georgia PSC, and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to be completed by July 2006. The Merger is not expected to have a material impact on the Company’s financial statements.

     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, the Company and Savannah Electric have filed an application with the Georgia PSC with respect to certain approvals that will be necessary to effectively complete the Merger. In particular, the Company and Savannah Electric plan to seek the approval of the Georgia PSC with respect to the following matters:

• the transfer of Savannah Electric’s generating facilities and certification of the generating facilities as the Company’s assets;

• amendments to the Company’s Integrated Resource Plan to add the current Savannah Electric’s customers and generating facilities;

• the transfer of Savannah Electric’s assigned service territory to the Company;

• adoption of the Company’s service rules and regulations to the current Savannah Electric customers;

• new fuel rate and base rate schedules that would apply to the Company’s sale of electricity to the current Savannah Electric customers;

• adoption of a “merger transition adjustment” rate that would be used to more closely align Savannah Electric’s existing base rates to those of the Company and a “merger transition credit” rate that would credit the additional revenues collected from former Savannah Electric customers to the Company’s existing customers; and

• the issuance of additional shares of the Company’s common stock to Southern Company in exchange for Southern Company’s shares of Savannah Electric common stock.

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Rate Plans

Under the terms of the 2004 Retail Rate Plan, which the Georgia PSC approved in December 2004, the Company’s earnings are evaluated against a retail return on common equity (ROE) range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates were increased by approximately $194 million and customer fees by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. In 2005, the Company recorded $2.7 million in revenue subject to refund related to earnings in excess of 12.25 percent retail ROE.

     The Company is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the rate order should be continued, modified, or discontinued. Until then, the Company may not file for a general base rate increase unless its projected retail ROE falls below 10.25 percent.

     Under the 2001 Retail Rate Plan, retail rates were decreased by $118 million effective January 1, 2002. Under the terms of the 2001 Retail Rate Plan, earnings were evaluated against a retail ROE range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return were to be applied to rate refunds, with the remaining one-third retained by the Company. The Company’s earnings in 2004, 2003, and 2002 were within the retail ROE range.

     Under the 2001 Retail Rate Plan, the Company discontinued recording accelerated depreciation and amortization and began amortizing the accumulated balance equally over three years as a credit to expense beginning in 2002. Also, the 2001 Retail Rate Plan required the Company to recognize capacity and operating and maintenance costs related to new Georgia PSC-certified PPAs evenly in rates over a three-year period ended December 31, 2004.

Fuel Hedging Program

In 2003, the Georgia PSC approved an order allowing the Company to implement a natural gas and oil procurement and hedging program. This order allows the Company to use financial instruments to hedge price and commodity risk associated with these fuels. The order limits the program in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including any net losses, are recovered as a fuel cost through the fuel cost recovery clause. Annual net financial gains from the hedging program will be shared with the retail customers receiving 75 percent and the Company retaining 25 percent of the total net gains. In 2005, the Company had a total net gain of $64.1 million, of which the Company retained $16 million.

Fuel Cost Recovery

On May 17, 2005, the Georgia PSC approved the Company’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets in the balance sheet. Under recovered fuel amounts for the periods subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, the Company would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with the Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. The Company has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, the Company and Savannah Electric will file a combined request in March 2006 to increase the Company’s fuel cost recovery rate.

     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Company and Savannah Electric generating fleet as well as the under recovered fuel balances existing at June 30, 2006. The new fuel cost recovery

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rate would be billed beginning in July 2006 to all of the Company’s customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.

     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of the Company’s fuel practices was initiated. The Company and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.

     Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable cost and amounts billed in current regulated rates. Accordingly, any increase in the billing factor would have no significant effect on the Company’s revenues or net income, but would increase annual cash flow.

Nuclear Performance Standards

Through December 2004, the Georgia PSC had adopted a three-year performance standard for the Company’s nuclear generating units. The performance standard was based on each unit’s capacity factor as compared to the average of all comparable U.S. nuclear units operating at a capacity factor of 50 percent or higher during the three-year period of evaluation. Depending on the performance of the units, the Company could receive a monetary award or penalty under the performance standards criteria. For the period 2002-2004, the Company’s performance fell within the criteria prescribed by the Georgia PSC; there was no associated award or penalty. Effective January 1, 2005, the Georgia PSC discontinued the nuclear performance standard.

Plant McIntosh Construction Project

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

     In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflected an approximate $16 million disallowance, of which $13 million was attributable to the Company, and reduced the Company’s net income by approximately $8 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Units 10 and 11 were placed into service at a total cost that did not exceed the certified amount. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates evenly over the three years ending 2007. See “Retail Regulatory Matters—Rate Plans” herein for additional information regarding the transfer of the Plant McIntosh construction project.

4. JOINT OWNERSHIP AGREEMENTS

The Company and an affiliate, Alabama Power, own equally all of the outstanding capital stock of SEGCO which owns electric generating units with a total rated capacity of 1,020 megawatts, as well as associated transmission facilities. The capacity of the units has been sold equally to the Company and Alabama Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes,

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debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice. The Company’s share of expenses included in purchased power from affiliates in the statements of income is as follows:

	2005		2004		2003
	(in millions)
Energy	$	54	$	51	$	55
Capacity		38		36		34
Total	$	92	$	87	$	89

     The Company owns undivided interests in plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG), the city of Dalton, Georgia, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company also jointly owns Plant McIntosh combustion- turbine common facilities and Plant McIntosh combined cycle units with Savannah Electric who operates the plants. The Company and Progress Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida, Inc.

     At December 31, 2005, the Company’s percentage ownership and investment (exclusive of nuclear fuel) in jointly owned facilities in commercial operation were as follows:

	Company						Accumulated
Facility (Type)	Ownership			Investment			Depreciation
				(in millions)
Plant Vogtle (nuclear)		45.7	%	$	3,311	*	$	1,809
Plant Hatch (nuclear)		50.1			935			492
Plant Wansley (coal)		53.5			395			172
Plant Scherer (coal)
Units 1 and 2		8.4			115			56
Unit 3		75.0			562			270
Plant McIntosh CC (combined cycle)		83.9			436			7
Plant McIntosh Common Facilities (combustion-turbine)		75.0			27			5
Rocky Mountain (pumped storage)		25.4			169	*		92
Intercession City (combustion-turbine)		33.3			12			2

* Investment includes write-offs

     At December 31, 2005, the portion of total construction work in progress related to Plants Wansley, Scherer, and Rocky Mountain was $8.3 million, $0.5 million, and $0.1 million, respectively, primarily for environmental projects.

     The Company’s proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income.

5. INCOME TAXES

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

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain

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deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $10 million payable to these subsidiaries in Accumulated Deferred Income Taxes on the balance sheets at December 31, 2005.

     The transfer of the Plant McIntosh construction project from Southern Power to the Company resulted in a deferred gain to Southern Power for federal income tax purposes. The Company will reimburse Southern Power for the remaining balance of the related deferred taxes of $5.3 million reflected in Southern Power’s future taxable income. $3.7 million of this payable to Southern Power is included in Other Deferred Credits and $1.6 million is included in Affiliated Accounts Payable in the balance sheet at December 31, 2005.

     The transfer of the Dahlberg, Wansley, and Franklin projects to Southern Power from the Company in 2001 and 2002 also resulted in a deferred gain for federal income tax purposes. Southern Power will reimburse the Company for the remaining balance of the related deferred taxes of $12.2 million reflected in the Company’s future taxable income. $10.8 million of this receivable from Southern Power is included in Other Deferred Debits and $1.4 million is included in Affiliated Accounts Receivable in the balance sheet at December 31, 2005.

     At December 31, 2005, tax-related regulatory assets were $501 million and tax-related regulatory liabilities were $159 million. The assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. The liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.

     Details of the federal and state income tax provisions are as follows:

	2005		2004		2003
	(in millions)
Total provision for income taxes:
Federal:
Current	$	173	$	116	$	143
Deferred		203		221		181
		376		337		324
State:
Current		26		12		24
Deferred		29		30		16
Deferred investment tax credits		—		—		2
Total	$	431	$	379	$	366

     The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	2,177		$	2,050
Property basis differences		558			577
Employee benefit obligations		163			149
Fuel clause under recovery		305			141
Premium on reacquired debt		69			72
Storm damage reserve		13			6
Other		74			81
Total		3,359			3,076
Deferred tax assets:
Federal effect of state deferred taxes		116			106
Other property basis differences		139			147
Other deferred costs		126			94
Employee benefit obligations		51			55
Other comprehensive income		23			22
Unbilled revenue		13			11
Other		33			19
Total		501			454
Total deferred tax liabilities, net		2,858			2,622
Portion included in current (liabilities) assets, net		(128	)		(66	)
Accumulated deferred income taxes in the balance sheets	$	2,730		$	2,556

     In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied

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Georgia Power Company 2005 Annual Report

as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $12 million in 2005, $12 million in 2004, and $15 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2005			2004			2003
Federal statutory rate		35	%		35	%		35	%
State income tax, net of federal deduction		3			3			3
Non-deductible book depreciation		1			1			1
Other		(1	)		(2	)		(2	)
Effective income tax rate		38	%		37	%		37	%

6. FINANCING

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

The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $969 million, which constitute substantially all of the assets of the trusts and are reflected in the balance sheets as Long-Term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the respective trusts’ payment obligations with respect to these securities. At December 31, 2005, preferred securities of $940 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Securities Due Within One Year

A summary of the scheduled maturities and redemptions of securities due within one year at December 31 is as follows:

	2005		2004
	(in millions)
Capital lease	$	3	$	2
Senior notes		150		450
Preferred stock		15		—
Total	$	168	$	452

     Serial maturities through 2010 applicable to total long-term debt and preferred stock are as follows: $168 million in 2006; $303 million in 2007; $3 million in 2008; $278 million in 2009; and $4 million in 2010.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company has incurred obligations in connection with the sale by public authorities of tax-exempt pollution control revenue bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2005 was $1.7 billion.

Senior Notes

The Company issued a total of $625 million of unsecured senior notes in 2005. The proceeds of these issues were used to redeem or repay at maturity long-term debt, to repay short-term indebtedness, and for other general corporate purposes. At December 31, 2005 and 2004, the Company had $2.6 billion and $2.4 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company.

Capital Leases

Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2005 and 2004, the Company had a

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capitalized lease obligation for its corporate headquarters building of $74 million and $77 million, respectively, with an interest rate of 8.1 percent. For ratemaking purposes, the Georgia PSC has treated the lease as an operating lease and has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. See Note 1 under “Regulatory Assets and Liabilities.”

Bank Credit Arrangements

At the beginning of 2006, the Company had credit arrangements with banks totaling $780 million, of which $778 million was unused. Of these facilities, $70 million expires at various times throughout 2006; $350 million expires in 2007, with the remaining $360 million expiring in 2010. The facilities that expire in 2006 provide the option of converting borrowings into a two-year term loan. The Company expects to renew its facilities, as needed, prior to expiration. The agreements contain stated borrowing rates. All the agreements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees are less than 1/8 of 1 percent for the Company. Compensating balances are not legally restricted from withdrawal. A fee is also paid to the agent bank.

     The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the arrangements. For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts. In addition, the credit arrangements contain cross default provisions that would trigger an event of default if the Company defaulted on other indebtedness above a specified threshold. At December 31, 2005, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings.

     The $778 million in unused credit arrangements provides liquidity support to the Company’s variable rate pollution control bonds. The amount of variable rate pollution control bonds outstanding requiring liquidity support as of December 31, 2005 was $106 million. In addition, the Company borrows under a commercial paper program and an extendible commercial note program. The amount of commercial paper outstanding at December 31, 2005 was $268 million. The amount of commercial paper outstanding at December 31, 2004 was $208 million. There were no outstanding extendible commercial notes at December 31, 2005. Commercial paper is included in notes payable on the balance sheets.

     During 2005, the peak amount of short-term debt outstanding was $549 million and the average amount outstanding was $242 million. The average annual interest rate on short-term debt in 2005 was 3.20 percent.

Financial Instruments

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. See Note 3 under “Retail Regulatory Matters – Fuel Hedging Program” for information on the Company’s fuel hedging program. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005, 2004, and 2003.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	26,643
Other comprehensive income		—
Net income		(81	)
Total fair value	$	26,562

     The fair value gain or loss for hedges that are recoverable through the regulatory fuel clauses are recorded in regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2008.

     The Company enters into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives are generally structured to mirror the critical terms of the hedged debt instruments; therefore, no material

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ineffectiveness has been recorded in earnings. In addition to interest rate swaps, the Company has also entered into certain options agreements that effectively cap its interest rate exposure in return for payment of a premium. In some cases, costless collars have been used that effectively establish a floor and a ceiling to interest rate expense.

     At December 31, 2005, the Company had $1.0 billion notional amounts of interest derivatives accounted for as cash flow hedges outstanding with net fair value gains as follows:

						Fair
						Value
	Weighted Average			Notional		Gain /
Maturity	Fixed Rate Paid			Amount		(Loss)
				(in millions)
2007		2.67%		$	300	$	2.4
2006-2007		2.09% -3.85	%*	$	400	$	1.2
2037		4.58% -5.75	%**	$	300	$	(1.1	)

*	Series of interest rate caps and collars (showing the lowest floor and highest cap) with variable rate based on one-month LIBOR
**	Interest rate collar

     The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. In 2005, 2004, and 2003, the Company settled gains (losses) totaling $0.9 million, $(12.4) million, and $(11.3) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. For the years 2005, 2004, and 2003, approximately $1.9 million, $3.9 million, and $3.4 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2006, pre-tax losses of approximately $0.5 million are expected to be reclassified from other comprehensive income to interest expense. The Company has gains/losses that are being amortized through 2017.

7. COMMITMENTS

Construction Program

The Company currently estimates property additions to be approximately $1.3 billion, $1.4 billion, and $1.3 billion in 2006, 2007, and 2008, respectively. These amounts include $44 million, $28 million, and $14 million in 2006, 2007, and 2008, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel Commitments” herein. The construction program is subject to periodic review and revision, and actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, changes in FERC rules and transmission regulations, revised load growth estimates, changes in environmental regulations, changes in existing nuclear plants to meet new regulatory requirements, increasing costs of labor, equipment, and materials, and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.

     The Company completed construction of Plant McIntosh Units 10 and 11 in June 2005 and has no other generating plants currently under construction. Construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet environmental standards, is ongoing.

Long-Term Service Agreements

The Company and Savannah Electric have entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. In summary, the LTSA stipulates that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

     In general, this LTSA is in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under this agreement are currently estimated at $186 million over the remaining term of the agreement, which may range up to 30 years. However, the LTSA contains various cancellation provisions at the option of the Company.

     The Company has also entered into an LTSA with GE through 2014 for neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently

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Georgia Power Company 2005 Annual Report

estimated at $13.1 million. The contract contains cancellation provisions at the option of the Company.

     Payments made to GE prior to the performance of any work are recorded as a prepayment in the balance sheets. Work performed by GE is capitalized or charged to expense as appropriate net of any joint owner billings, based on the nature of the work.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005.

     Total estimated minimum long-term obligations at December 31, 2005 were as follows:

	Commitments
	Natural				Nuclear
	Gas		Coal		Fuel
	(in millions)
2006	$	577	$	1,579	$	44
2007		325		1,313		28
2008		200		907		14
2009		257		422		11
2010		254		272		14
2011 and thereafter		2,047		40		64
Total	$	3,660	$	4,533	$	175

     Additional commitments for coal and for nuclear fuel will be required to supply the Company’s future needs.

     SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company Gas. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company Gas as a contracting party under these agreements.

Purchased Power Commitments

The Company has commitments regarding a portion of a 5 percent interest in Plant Vogtle owned by MEAG that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG’s bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit’s variable operating costs. Except as noted below, the cost of such capacity and energy is included in purchased power from non-affiliates in the Company’s statements of income. Capacity payments totaled $54 million, $55 million, and $57 million in 2005, 2004, and 2003, respectively. The current projected Plant Vogtle capacity payments are:

	Capacity Payments
	(in millions)
2006	$	53
2007		52
2008		54
2009		54
2010		54
2011 and thereafter		261
Total	$	528

     Portions of the payments noted above relate to costs in excess of Plant Vogtle’s allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off.

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NOTES (continued )
Georgia Power Company 2005 Annual Report

     The Company has entered into other various long-term commitments for the purchase of electricity. Estimated total long-term obligations under these commitments at December 31, 2005 were as follows:

	Commitments
			Non-
	Affiliated		Affiliated
	(in millions)
2006	$	205	$	85
2007		205		86
2008		205		87
2009		205		68
2010		112		66
2011 and thereafter		455		278
Total	$	1,387	$	670

Operating Leases

The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $38 million for 2005, $38 million for 2004, and $36 million for 2003.

     At December 31, 2005, estimated minimum lease payments for these noncancelable operating leases were as follows:

	Minimum Lease Payments
	Rail Cars		Other		Total
	(in millions)
2006	$	17	$	17	$	34
2007		17		14		31
2008		16		11		27
2009		15		9		24
2010		14		6		20
2011 and thereafter		48		10		58
Total	$	127	$	67	$	194

     In addition to the rental commitments above, the Company has obligations upon expiration of certain rail car leases with respect to the residual value of the leased property. These leases expire in 2011 and the Company’s maximum obligation is $68 million. At the termination of the leases, at the Company’s option, the Company may either exercise its purchase option or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company’s payments under the residual value obligation. A portion of the rail car lease obligations is shared with the joint owners of plants Scherer and Wansley. Rental expenses related to the rail car leases are fully recoverable through the fuel cost recovery clause as ordered by the Georgia PSC.

Guarantees

Alabama Power has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Alabama Power has also guaranteed $50 million in senior notes issued by SEGCO. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company’s then proportionate ownership of stock of SEGCO if Alabama Power is called upon to make such payment under its guaranty.

     As discussed earlier in this note under “Operating Leases,” the Company has entered into certain residual value guarantees related to rail car leases.

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2005, 1,551 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2003 to 2005 for the options granted

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NOTES (continued)
Georgia Power Company 2005 Annual Report

to the Company’s employees under the stock option plan is summarized below:

	Shares			Average
	Subject			Option Price
	To Option			Per Share
Balance at December 31, 2002		7,178,597		$	19.73
Options granted		1,455,517			27.98
Options canceled		(54,860	)		25.47
Options exercised		(1,428,273	)		16.92
Balance at December 31, 2003		7,150,981			21.92
Options granted		1,434,915			29.50
Options canceled		(6,371	)		25.99
Options exercised		(1,450,309	)		18.25
Balance at December 31, 2004		7,129,216			24.19
Options granted		1,427,618			32.71
Options canceled		(12,910	)		23.75
Options exercised		(1,838,033	)		21.23
Balance at December 31, 2005		6,705,891		$	26.82
Options exercisable:
At December 31, 2003		3,956,234
At December 31, 2004		4,304,091
At December 31, 2005		3,989,722

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares (in thousands)		991		2,922		2,794
Average remaining life (in years)		4.2		6.0		8.5
Average exercise price	$	17.25	$	25.94	$	31.13
Exercisable:
Shares (in thousands)		991		2,496		503
Average exercise price	$	17.25	$	25.59	$	29.75

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments Act, the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company’s nuclear power plants. The Act provides funds up to $10.76 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $101 million per incident for each licensed reactor it operates but not more than an aggregate of $15 million per incident to be paid in a calendar year for each reactor. Such maximum assessment for the Company, excluding any applicable state premium taxes — based on its ownership and buyback interests — is $203 million per incident but not more than an aggregate of $30 million to be paid for each incident in any one year.

     The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members’ nuclear generating facilities.

     Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL.

     NEIL also covers additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases the maximum limit allowed by NEIL subject to ownership limitations and has elected a 12 week waiting period.

     Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $48 million.

     Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance. Both companies, however, revised their policy terms on

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NOTES (continued)
Georgia Power Company 2005 Annual Report

a prospective basis to include an industry aggregate for all “non-certified” terrorist acts i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.

     For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

     All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2005 and 2004 is as follows:

					Net Income
					After
					Dividends on
	Operating		Operating		Preferred
Quarter Ended	Revenues		Income		Stock
			(in millions)
March 2005	$	1,370	$	286	$	142
June 2005		1,459		311		158
September 2005		2,219		626		355
December 2005		1,586		165		60
March 2004	$	1,199	$	285	$	144
June 2004		1,353		322		156
September 2004		1,582		486		287
December 2004		1,237		166		71

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

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Georgia Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands)	$	6,634,203	$	5,370,808	$	4,913,507	$	4,822,460	$	4,965,794
Net Income after Dividends on Preferred Stock (in thousands)	$	714,999	$	658,001	$	630,577	$	617,629	$	610,335
Cash Dividends on Common Stock (in thousands)	$	556,100	$	565,500	$	565,800	$	542,900	$	527,300
Return on Average Common Equity (percent)		14.15		13.95		14.05		13.99		14.12
Total Assets (in thousands)	$	17,047,783	$	15,822,338	$	14,850,754	$	14,342,656	$	14,447,973
Gross Property Additions (in thousands)	$	906,248	$	1,126,064	$	742,810	$	883,968	$	1,389,751
Capitalization (in thousands) :
Common stock equity	$	5,214,535	$	4,890,561	$	4,540,211	$	4,434,447	$	4,397,485
Preferred stock		—		14,609		14,569		14,569		14,569
Mandatorily redeemable preferred securities		—		—		940,000		940,000		789,250
Long-term debt payable to affiliated trusts		969,073		969,073		—		—		—
Long-term debt		4,179,218		3,709,852		3,762,333		3,109,619		2,961,726
Total (excluding amounts due within one year)	$	10,362,826	$	9,584,095	$	9,257,113	$	8,498,635	$	8,163,030
Capitalization Ratios (percent) :
Common stock equity		50.3		51.0		49.0		52.2		53.9
Preferred stock		—		0.2		0.2		0.2		0.2
Mandatorily redeemable preferred securities		—		—		10.2		11.1		9.6
Long-term debt payable to affiliated trusts		9.4		10.1		—		—		—
Long-term debt		40.3		38.7		40.6		36.5		36.3
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
Preferred Stock -
Moody’s	Baa1		Baa1		Baa1		Baa1		Baa1
Standard and Poor’s	BBB+		BBB+		BBB+		BBB+		BBB+
Fitch		A		A		A		A		A
Unsecured Long-Term Debt -
Moody’s		A2		A2		A2		A2		A2
Standard and Poor’s		A		A		A		A		A
Fitch		A+		A+		A+		A+		A+
Customers (year-end) :
Residential		1,832,520		1,801,426		1,768,662		1,734,430		1,698,407
Commercial		270,373		265,543		258,276		250,993		244,674
Industrial		8,206		7,676		7,899		8,240		8,046
Other		3,536		3,482		3,434		3,328		3,239
Total		2,114,635		2,078,127		2,038,271		1,996,991		1,954,366
Employees(year-end)		8,713		8,731		8,714		8,837		9,048

N/A = Not Applicable.

II-185

SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Georgia Power Company 2005 Annual Report

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

II-186

GULF POWER COMPANY

FINANCIAL SECTION

II-187

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Gulf Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements (pages II-208 to II-231) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

II-188

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Company 2005 Annual Report

OVERVIEW

Business Activities

Gulf Power Company (the Company) operates as a vertically integrated utility providing electricity to customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast.

     Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.

     Hurricanes Dennis and Katrina hit the Gulf Coast of Florida in July 2005 and August 2005, respectively, damaging portions of the Company’s service area. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida, causing substantial damage within the Company’s service area. In February 2005, the Florida Public Service Commission (PSC) approved the recovery of the Company’s storm damage costs related to Hurricane Ivan through a two-year surcharge that began in April 2005. Later in 2005, the Florida Legislature also approved securitized financing for hurricane costs and in February 2006, the Company filed with the Florida PSC requesting permission to issue securitized bonds to recover the remaining costs of these storms and to replenish its property damage reserve. See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively for additional information.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective energy to over 400,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance was adjusted to exclude the impact of outages at Plants Crist and Smith, which were attributed to manufacturer and/or vendor defects as well as removing the effects of Hurricanes Dennis and Katrina. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected economic conditions. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s 2005 results compared with its targets for some of these indicators are reflected in the following chart:

Key	2005	2005
Performance	Target	Actual
Indicator	Performance	Performance
Customer Satisfaction	Top quartile performance in customer surveys	Top quartile
Peak Season EFOR	3.00%	1.50%
Net Income	$75.0 million	$75.2 million

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2005 reflects the focus that management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

Earnings

The Company’s 2005 net income after dividends on preferred stock was $75.2 million, an increase of $7.0 million from the previous year. In 2004, earnings were $68.2 million, a decrease of $0.8 million from the previous year. In 2003, earnings were $69.0 million, an increase of $2.0 million from the previous year. The

II-189

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2005 Annual Report

increase in earnings in 2005 is due primarily to higher retail sales and lower non-fuel operating expenses, excluding expenses related to Hurricane Ivan storm damage, which are offset by revenues and do not affect earnings. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein. The decrease in earnings in 2004 was due primarily to higher operating expenses related to replenishing property damage reserves and increased expenses related to employee benefits. The improvement in earnings in 2003 was primarily due to higher operating revenues related to an increase in base rates, offset somewhat by higher operating expenses and increases in depreciation expense primarily related to the commercial operation of Plant Smith Unit 3.

RESULTS OF OPERATIONS

A condensed statement of income follows:

				Increase (Decrease)
	Amount			From Prior Year
	2005			2005			2004			2003
	(in thousands)
Operating revenues	$	1,083,622		$	123,491			$	82,434		$	57,230
Fuel		415,789			48,634				50,652			42,643
Purchased power		98,397			32,500				15,740			(12,841	)
Other operation and maintenance		249,770			20,058				19,012			10,625
Depreciation and amortization		85,002			2,203				477			5,308
Taxes other than income taxes		76,387			6,531				3,741			5,082
Total operating expenses		925,345			109,926				89,622			50,817
Operating income		158,277			13,565				(7,188	)		6,413
Total other income and (expense)		(37,326	)		(749	)			5,219			(706	)
Income taxes		44,981			5,286				(1,182	)		3,733
Net Income		75,970			7,530				(787	)		1,974
Dividends on Preferred and Preference Stock		761			544				—			—
Net Income after Dividends on Preferred and Preference Stock	$	75,209		$	6,986			$	(787	)	$	1,974

Revenues

Operating revenues increased in 2005 when compared to 2004 and 2003. The following table summarizes the changes in operating revenues for the past three years:

	2005			2004			2003
	(in thousands)
Retail – Prior Year	$	736,870		$	699,174		$	665,836
Change in —
Base rates		—			—			22,000
Sales growth		11,568			4,896			7,040
Weather		(4,223	)		3,313			(6,757	)
Fuel and other cost recovery		120,644			29,487			11,055
Retail – Current Year		864,859			736,870			699,174
Sales for resale —
Non-affiliates		84,346			73,537			76,767
Affiliates		91,352			110,264			63,268
Total sales for resale		175,698			183,801			140,035
Other operating revenues		43,065			39,460			38,488
Total operating revenues	$	1,083,622		$	960,131		$	877,697
Percent change		12.9	%		9.4	%		7.0	%

     Retail revenues increased $128.0 million, or 17.4 percent, in 2005, $37.7 million, or 5.4 percent, in 2004, and $33.3 million, or 5.0 percent, in 2003. The significant factors driving these changes are shown in the table above.

     Fuel and other cost recovery includes recovery provisions for fuel expenses and the energy component of purchased power costs, energy conservation costs, purchased power capacity costs, and environmental compliance costs. Annually, the Company petitions for recovery of projected costs including any true-up amount from prior periods, and approved rates are implemented each January. Other cost recovery also includes revenues related to the recovery of expenses related to Hurricane Ivan as approved by the Florida PSC. The recovery provisions generally equal the related expenses and have no material effect on net income. See Note 1 to the financial statements under “Revenues,” “Property Damage Reserve,” and “Environmental Cost Recovery” and Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery” and “– Storm Damage Cost Recovery” for additional information.

II-190

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2005 Annual Report

     Sales for resale were $175.7 million in 2005, a decrease of $8.1 million, or 4.4 percent, as compared to 2004, primarily due to lower energy sales to affiliates resulting from decreases in the Company’s available generation as a result of outages at Plants Crist and Smith, which were attributed to manufacturer and/or vendor defects. Sales for resale were $183.8 million in 2004, an increase of $43.8 million, or 31.3 percent, as compared to 2003, primarily due to energy sales to affiliates at a higher unit cost resulting from higher incremental fuel prices. Sales for resale were $140.0 million in 2003, an increase of $22.5 million, or 19.1 percent, as compared to 2002, primarily due to increased energy sales to affiliates reflecting the availability of additional generation following the commercial operation of Plant Smith Unit 3. Sales to and purchases from affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These transactions do not have a significant impact on earnings, since the energy is generally sold at marginal cost and energy purchases are generally offset by revenues through the Company’s fuel cost recovery clause.

     Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to other Florida utilities. Revenues from contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. The capacity and energy components under these unit power contracts were as follows:

	2005		2004		2003
	(in thousands)
Unit Power —
Capacity	$	20,852	$	18,780	$	18,598
Energy		33,206		29,360		30,892
Total	$	54,058	$	48,140	$	49,490

     During 2004, the Company entered into agreements with Florida Power & Light (FP&L), Progress Energy Florida, and Flint Electric Membership Corporation to provide capacity beginning in June 2010 through December 2015. See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for additional information.

     Other operating revenues increased $3.6 million, $1.0 million, and $1.4 million in 2005, 2004, and 2003, respectively, primarily due to an increase in franchise fees, which are proportional to changes in revenue.

Energy Sales

Kilowatt-hour (KWH) sales for 2005 and the percent changes by year were as follows:

	KWH		Percent Change
	2005		2005			2004			2003
	(millions)
Residential		5,319		2.0	%		2.2	%		(0.8	)%
Commercial		3,736		1.1			2.2			1.7
Industrial		2,161		2.3			(1.6	)		4.5
Other		23		0.7			0.4			4.7
Total retail		11,239		1.7			1.5			1.0
Sales for resale
Non-affiliates		2,296		1.7			(9.9	)		16.1
Affiliates		1,976		(36.8	)		28.1		��	41.8
Total		15,511		(5.6	)		3.8			8.0

     Residential sales increased 2.0 percent in 2005 primarily due to customer growth, as compared to 2004. Residential sales increased 2.2 percent in 2004 due to more favorable weather conditions and customer growth, as compared to 2003. Residential sales decreased 0.8 percent in 2003 primarily due to milder summer weather, as compared to 2002.

     Commercial sales increased 1.1 percent in 2005, as compared to 2004, primarily due to customer growth. Commercial sales increased 2.2 percent in 2004, as compared to 2003, primarily due to more favorable weather conditions and customer growth. Commercial sales increased 1.7 percent in 2003, as compared to 2002, primarily due to customer growth, which offset milder summer weather.

     Industrial sales increased 2.3 percent in 2005, as compared to 2004, primarily due to additional sales to customers with gas-fired cogeneration resulting from high natural gas prices. Industrial sales decreased 1.6 percent in 2004, as compared to 2003, primarily due to the short-term outage experienced as a result of Hurricane Ivan in September 2004. Industrial sales increased 4.5 percent in 2003, when compared to 2002, primarily due to additional

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sales to customers with gas-fired cogeneration resulting from high natural gas prices.

     Total energy sales to retail customers are projected to increase at a compound average growth rate of 1.8 percent during the period 2006 through 2010 due to customer growth, assuming normal weather conditions.

     Sales for resale to non-affiliates increased 1.7 percent in 2005, decreased 9.9 percent in 2004, and increased 16.1 percent in 2003, each as compared to the prior year primarily as a result of fluctuations in the fuel cost to produce energy sold to non-affiliated utilities under long-term contracts and energy sold to other non-affiliated utilities under short-term contracts. The degree to which oil and natural gas prices, which are the primary fuel sources for these customers, differ from the Company’s fuel costs will influence these changes in sales. The fluctuations in sales have a minimal effect on earnings because the energy is generally sold at variable cost.

Expenses

Total operating expenses increased $109.9 million, or 13.5 percent, in 2005, $89.6 million, or 12.3 percent, in 2004, and $50.8 million, or 7.5 percent, in 2003 over the amount recorded in the prior year primarily due to higher fuel and operation and maintenance expenses.

Fuel and Purchased Power

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generation resources. Fuel expense increased $48.6 million, or 13.2 percent, in 2005, $50.7 million, or 16.0 percent, in 2004, and $42.6 million, or 15.6 percent, in 2003, compared to the prior year primarily due to increased demand for energy and higher average costs of fuel.

     The amount and sources of generation, the average cost of fuel per net KWH generated, and the average costs of purchased power were as follows:

	2005		2004		2003
Total generation (millions of KWH)		15,024		15,841		14,988
Sources of generation (percent) —
Coal		86		84		87
Gas		14		16		13
Average cost of fuel per net KWH generated (cents)		2.77		2.32		2.11
Average cost of purchased power per net KWH (cents)		8.39		4.97		3.29

     Purchased power expense in 2005 increased $32.5 million, or 49.3 percent, as compared to 2004, primarily due to an increase in volume and cost of energy purchased from affiliates to meet the Company’s higher territorial load. Purchased power expense in 2004 increased $15.7 million, or 31.4 percent, as compared to 2003, primarily due to increased power purchases from merchant generation resources to minimize total system production cost. Purchased power expense decreased in 2003 by $12.8 million, or 20.4 percent, as compared to 2002, primarily due to a decrease in the volume of energy needed to meet the Company’s load requirements.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China, as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues by the Company’s fuel cost recovery provisions.

Other Operation and Maintenance

In 2005, other operation and maintenance expenses increased $20.1 million, or 8.7 percent, as compared to

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the prior year primarily due to the recovery of $20.4 million in Hurricane Ivan restoration costs as approved by the Florida PSC. Since these expenses are recognized as revenues are collected, there is no impact on net income. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. In 2004, other operation and maintenance expenses increased $19.0 million, or 9.0 percent, as compared to the prior year primarily due to increases of $7.9 million in the property damage reserve, $2.9 million in the accrued expenses for uninsured litigation and workers compensation claims, $3.4 million for employee benefit expenses, and $2.5 million for production expenses. In 2003, other operation and maintenance expenses increased $10.6 million, or 5.3 percent, as compared to the prior year primarily due to an increase of $1.6 million of customer accounts expense and an increase of $7.1 million in the property damage reserve. See Notes 1 and 3 to the financial statements under “Property Damage Reserve” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively, for additional information on the property damage reserve.

Depreciation and Amortization

Depreciation and amortization expense increased $2.2 million, or 2.7 percent, in 2005 as compared to the prior year primarily due to the completion of environmental control projects at Plant Crist Unit 7. Depreciation and amortization expense remained relatively flat in 2004 as compared to the prior year due to no significant change in depreciable assets. Depreciation and amortization expense increased $5.3 million, or 6.9 percent, in 2003 as compared to the prior year primarily due to the commercial operation of Plant Smith Unit 3. The 2003 increase also reflects the amortization of a regulatory asset related to corporate facilities, in accordance with an order from the Florida PSC.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $6.5 million, or 9.3 percent, in 2005, $3.7 million, or 5.7 percent, in 2004, and $5.1 million, or 8.3 percent, in 2003 primarily due to increases in franchise and gross receipts taxes, which are directly related to the increase in retail revenues. Taxes other than income taxes for 2003 also increased as a result of higher property taxes.

Other Income and (Expense)

The equity portion of allowance for funds used during construction (AFUDC) decreased $0.7 million, or 37.1 percent, in 2005 and increased $1.1 million, or 160.7 percent, in 2004 as compared to the prior year primarily due to environmental control projects at Plant Crist Unit 7. AFUDC decreased $2.3 million, or 76.1 percent, in 2003 as compared to the prior year primarily due to the completion of Plant Smith Unit 3. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” herein and Note 1 to the financial statements under “Allowance for Funds Used During Construction (AFUDC)” for additional information.

     Interest income increased $2.6 million, or 210.9 percent, in 2005 as compared to the prior year primarily due to interest received from a tax refund resulting from Hurricane Ivan and interest received related to the recovery of financing costs associated with Hurricane Ivan. See FUTURE EARNINGS POTENTIAL – “Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. Interest income remained relatively flat in 2004 and 2003 as compared to the prior year.

     Interest expense, net of amounts capitalized increased $4.2 million, or 13.5 percent, in 2005 as compared to the prior year as the result of higher interest rates on variable-rate pollution control bonds and an increase in outstanding short-term debt as a result of hurricane related costs. Interest expense decreased $2.1 million, or 5.5 percent, in 2004 as compared to the prior year and $1.8 million, or 4.6 percent, in 2003 as compared to the prior year primarily as the result of refinancing higher cost securities.

     Other deductions decreased $1.4 million, or 32.2 percent, in 2005 and $1.5 million, or 25.7 percent, in 2004 and increased $1.4 million, or 33.9 percent, in 2003 as compared to the prior years as a result of changes in charitable contributions.

Effects of Inflation

The Company is subject to rate regulation based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation

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

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant Scherer. See Note 4 to the financial statements for information on the Company’s ownership interest in Plant Scherer Unit 3. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled.

     On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters – New Source Review Actions” for additional information.

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     The Company believes that it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The Florida Department of Environmental Protection (FDEP) formally adopted the 2002 NSR rules in January 2006, but did not adopt the provisions vacated by the court. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Florida’s implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Environmental Statutes and Regulations

General

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act.

     Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $171.5 million in capital projects to comply with these requirements, with annual totals of $45.3 million, $67.2 million, and $37.7 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $761 million, including $48 million, $131 million, and $141 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost,

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availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. The Florida Legislature has adopted legislation that allows a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The legislation is discussed in Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery.” Substantially all of the costs for the Clean Air Act and other new environmental legislation discussed below are expected to be recovered through the environmental cost recovery clause.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $52.4 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂ and NO_x emissions, to maintain compliance with existing regulations, and to meet new requirements.

     In 2005, the Company substantially completed the terms of a 2002 agreement with the State of Florida calling for NO_x emission reductions at Plant Crist to help ensure attainment of the new standards in the Pensacola, Florida area. The conditions of the agreement, which required installing additional controls on Plant Crist units and retiring Plant Crist Units 1, 2, and 3, will be fully implemented by the end of 2006 at a cost of approximately $134.4 million, of which $4.3 million remains to be spent.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. With the exception of Macon, Georgia, where Plant Scherer is located, no area within the Company’s service area has been designated as nonattainment under the eight-hour ozone standard. State implementation plans, including new emission control regulations necessary to bring nonattainment areas into attainment are required for most areas by June 2007. These state implementation plans could require further reductions in NO_x emissions from power plants.

     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for areas within Georgia, and the EPA proposed a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO₂ and NO_x emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including Florida and Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power

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plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

Environmental Remediation

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

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change, and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 – 2012. The Company is continuing to evaluate future energy and emissions profiles relative to the Climate VISION

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program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, the Company, Mississippi Power, Savannah Electric, Southern Power, and Southern Company Services, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an

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adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund amounts previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. The Company has received similar requests from other entities totaling approximately $6.7 million. The Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Transmission

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

PSC Matters

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Florida PSC. Over the past year, the Company has continued to experience higher than expected fuel costs for coal and natural gas. At December 31, 2005 and 2004, the under recovered balance was $31.6 million and $7.9 million, respectively, primarily due to increased costs for coal and natural gas. The Company continuously monitors the under recovered fuel cost balance in light of these higher fuel costs. If the projected fuel revenue over or under recovery exceeds 10 percent of the projected fuel costs for the period, the Company is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary.

     In December 2005, the Florida PSC approved an increase of approximately 9 percent in the fuel factor for retail customers, effective with billings beginning January 2006. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on the Company’s revenues or net income, but would change annual cash flow.

Storm Damage Cost Recovery

Under authority granted by the Florida PSC, the Company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property. See Note 1 to the financial statements under “Property Damage Reserve” for additional information.

     In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama causing substantial damage to the Company’s service territory. The related costs charged to the Company’s property damage reserve as of December 31, 2004 were $93.5 million. In February 2005, the Citizens of the State of Florida through the Office of Public Counsel, the Florida Industrial Power Users Group, and the Company filed a Stipulation and Settlement (Stipulation) with the Florida PSC, which the Florida PSC subsequently approved in March 2005, allowing the Company to recover the retail portion of $51.7 million of Hurricane Ivan storm damage costs, plus interest and revenue taxes, through a monthly surcharge applied to

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retail customer bills for a 24-month period that began in April 2005. As of December 31, 2005, the Company had recovered $21.2 million of these costs. Under the Stipulation, the Company also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused additional damage in the Company’s service area. Hurricanes Dennis and Katrina restoration costs were approximately $64 million, of which approximately $56 million relates to operation and maintenance expenses. Approximately $1 million of these costs is expected to be covered through insurance.

     Prior to Hurricane Ivan, the Company’s reserve balance was approximately $27.8 million. The Company made discretionary accruals to the reserve of $6 million and $15 million in 2005 and 2004, respectively. As of December 31, 2005, the deficit balance in the Company’s property damage reserve accounts totaled approximately $43.6 million, of which approximately $3.5 million and $40.1 million, respectively, is included in the balance sheets herein under Current Assets and Deferred Charges and Other Assets. The established policy of the Florida PSC, as recently reaffirmed by its decision following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge.

     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, the Company filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over eight years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve the Company’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish the Company’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since the Company will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on the Company’s net income, but would increase cash flow.

     See Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information.

Other Matters

On September 15, 2005, the Company’s Board of Directors, and on October 27, 2005, the sole shareholder of the Company at that time, approved a Plan of Domestication pursuant to Maine law in order to domesticate the Company as a Florida corporation. By domesticating the Company in the same state where it operates as an electric utility subject to state regulation, the Company simplified certain state and federal regulatory compliance requirements. The Company was formed in 1925 as a Maine corporation and was qualified to do business in Florida as a foreign corporation the following year when it began operations as an electric utility. The Company was also admitted to do business in Mississippi in 1976 and in Georgia in 1984. The Company has maintained its principal place of business in Florida continuously since 1926. The domestication was effective as of November 2, 2005. The Company is now a Florida corporation. Under the applicable provisions of Florida law, the Company’s legal existence was uninterrupted, with only its state of incorporation changed.

     In 2004, Georgia Power and the Company entered into PPAs with FP&L and Progress Energy Florida. Under the agreements, Georgia Power and the Company will provide FP&L and Progress Energy Florida with 165 megawatts and 74 megawatts, respectively, of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2015. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered. The Florida PSC approved the contracts in 2005.

     Also in 2004, Georgia Power and the Company entered into a PPA with Flint Electric Membership Corporation. Under the agreement, Georgia Power and the Company will provide Flint Electric Membership Corporation with 75 megawatts of capacity annually from

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the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2019. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered.

     In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pre-tax pension income of approximately $0.8 million, $2.5 million, and $4.9 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were $4.8 million, $5.1 million, and $4.9 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

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

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

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting

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principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company’s financial statements. These events or conditions include the following:

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

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

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

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

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

Unbilled Revenues

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

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on the Company’s financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $9.1 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”

Stock Options

On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be stable at December 31, 2005. Net cash flow from operating activities totaled $152.7 million, $143.2 million, and $191.2 million for 2005, 2004, and 2003, respectively. The increase from 2004 to 2005 is due primarily to the recovery of Hurricane Ivan restoration costs. The majority

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2005 Annual Report

of the decrease from 2003 to 2004 is due to payments related to storm damage from Hurricane Ivan. See “Financing Activities” herein for additional information. Property additions were $142.6 million in 2005. Funds for the Company’s property additions were provided by operating activities, capital contributions, and other financing activities. See the statements of cash flows for additional information.

     The Company’s ratio of common equity to total capitalization, including short-term debt, was 43.0 percent in 2005, 43.2 percent in 2004, and 45.3 percent in 2003. See Note 6 to the financial statements for additional information.

     The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.

     The Company has no restrictions on the amounts of unsecured indebtedness it may incur. However, the Company is required to meet certain coverage requirements specified in its mortgage indenture and corporate charter in order to issue new first mortgage bonds and preferred or preference stock. The Company’s coverage ratios are high enough to permit, at present interest rate levels, any foreseeable security sales. The amount of securities that the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.

     The issuance of securities is subject to regulatory approval by the Florida PSC pursuant to its rules and regulations. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

     The Company’s current liabilities exceed current assets due to the scheduled maturity of $37.1 million of long-term debt in 2006. See “Financing Activities” herein for additional information.

     To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2006, the Company had approximately $3.8 million of cash and cash equivalents, along with $120.5 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire during 2006. The Company plans to renew these lines of credit during 2006. In addition, the Company has substantial cash flow from operating activities. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. There is no cross affiliate credit support. At December 31, 2005, the Company had $15 million in commercial paper notes and $75 million in bank notes outstanding.

Financing Activities

During 2005, the Company issued $60 million of senior notes. A portion of the proceeds of this issuance was used for the legal defeasance of $30 million of principal of first mortgage bonds. The remainder of the funds from the sale of senior notes was used for general corporate purposes. In October 2005, the Company entered into a $60 million revolving credit agreement and a $75 million 364-day bank loan. A portion of these facilities was used to fund or refinance costs related to Hurricanes Ivan, Dennis, and Katrina with the remainder used to support the Company’s

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increased obligations with respect to its commercial paper program, which will also be used to fund storm-related costs. In addition, in October 2005, the Company redeemed all outstanding shares of its three preferred stock issues, totaling $4.2 million, in conjunction with the domestication of the Company as a Florida corporation. In November 2005, the Company issued $55 million of preference stock. The funds resulting from this issuance were used for general corporate purposes. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” and “– Other Matters” herein for additional information.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3, or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $5 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $10 million. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price management activities. At December 31, 2005, the Company had no material exposure related to these agreements.

Market Price Risk

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

     Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for natural gas purchases. The Company has implemented a fuel-hedging program with the approval of the Florida PSC.

     The weighted average interest rate on $144.6 million variable long-term debt that has not been hedged at January 1, 2006 was 3.3 percent. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $1.4 million at January 1, 2006. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

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

	Changes in Fair Value
	2005			2004
	(in thousands)
Contracts beginning of year	$	317		$	2,503
Contracts realized or settled		(15,023	)		(8,409	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		26,232			6,223
Contracts end of year	$	11,526		$	317

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

	Source of 2005 Year-End
	Valuation Prices
	Total			Maturity
	Fair Value			2006			2007-2008
	(in thousands)
Actively quoted	$	11,568		$	7,770		$	3,798
External sources		(42	)		(42	)		—
Models and other methods		—			—			—
Contracts end of Year	$	11,526		$	7,728		$	3,798

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     Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the Company’s fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s fuel cost recovery clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	11,540
Other comprehensive income		—
Net income		(14	)
Total fair value	$	11,526

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

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $163 million in 2006, $221 million in 2007, and $221 million in 2008. The construction program also includes $48 million in 2006, $131 million in 2007, and $141 million in 2008 for environmental expenditures. Actual construction costs may vary from these estimates because of changes in such factors as the following: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

     The Company does not have any new generating capacity under construction. Construction of new transmission and distribution facilities and capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, is ongoing.

     As discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC and the Florida PSC.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2005 Annual Report

			2007-		2009-		After
Contractual Obligations	2006		2008		2010		2010		Total
					(in thousands)
Long-term debt(a) —
Principal	$	37,075	$	—	$	—	$	624,721	$	661,796
Interest		33,055		61,592		61,592		625,399		781,638
Commodity derivative obligations(b)		2,444		8		—		—		2,452
Preference stock dividends(c)		3,300		6,600		6,600		—		16,500
Operating leases		4,875		7,363		4,169		4,170		20,577
Purchase commitments(d) —
Capital(e)		162,711		441,554		—		—		604,265
Coal		240,647		92,694		—		—		333,341
Natural gas(f)		123,447		116,683		37,772		204,030		481,932
Long-term service agreements		5,711		13,077		16,203		43,064		78,055
Postretirement benefit trusts(g)		70		140		—		—		210
Total	$	613,335	$	739,711	$	126,336	$	1,501,384	$	2,980,766

(a)	All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization.
(b)	For additional information, see Notes 1 and 6 to the financial statements herein.
(c)	Preference stock does not mature; therefore, amounts are provided for the next five years only.
(d)	The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $250 million, $230 million, and $211 million, respectively.
(e)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)	Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)	The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company’s retail sales growth, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against the Company, FERC matters, and IRS audits;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

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STATEMENTS OF INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report

	2005			2004			2003
				(in thousands)
Operating Revenues:
Retail sales	$	864,859		$	736,870		$	699,174
Sales for resale —
Non-affiliates		84,346			73,537			76,767
Affiliates		91,352			110,264			63,268
Other revenues		43,065			39,460			38,488
Total operating revenues		1,083,622			960,131			877,697
Operating Expenses:
Fuel		415,789			367,155			316,503
Purchased power —
Non-affiliates		29,995			30,720			17,137
Affiliates		68,402			35,177			33,020
Other operations		176,620			160,635			140,166
Maintenance		73,150			69,077			70,534
Depreciation and amortization		85,002			82,799			82,322
Taxes other than income taxes		76,387			69,856			66,115
Total operating expenses		925,345			815,419			725,797
Operating Income		158,277			144,712			151,900
Other Income and (Expense):
Interest income		3,804			1,224			888
Interest expense, net of amounts capitalized		(35,727	)		(31,482	)		(31,069	)
Interest expense to affiliate trusts		(4,590	)		(3,443	)		—
Distributions on mandatorily redeemable preferred securities		—			(1,113	)		(7,085	)
Other income (expense), net		(813	)		(1,763	)		(4,530	)
Total other income and (expense)		(37,326	)		(36,577	)		(41,796	)
Earnings Before Income Taxes		120,951			108,135			110,104
Income taxes		44,981			39,695			40,877
Net Income		75,970			68,440			69,227
Dividends on Preferred and Preference Stock		761			217			217
Net Income After Dividends on Preferred and Preference Stock	$	75,209		$	68,223		$	69,010

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

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2004, and 2003
Gulf Power Company 2005 Annual Report

	2005			2004			2003
				(in thousands)
Operating Activities:
Net income	$	75,970		$	68,440		$	69,227
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		90,890			88,772			87,949
Deferred income taxes		33,161			46,255			2,303
Pension, postretirement, and other employee benefits		375			(895	)		(717	)
Tax benefit of stock options		3,502			3,063			1,768
Hedge settlements		—			—			(3,266	)
Other, net		3,958			11,402			6,795
Changes in certain current assets and liabilities —
Receivables		(46,248	)		543			8,165
Fossil fuel stock		(11,740	)		2,355			1,837
Materials and supplies		3,785			(831	)		(1,091	)
Prepaid income taxes		31,898			(32,343	)		12,701
Property damage cost recovery		20,045			—			—
Other current assets		3,453			2,721			(704	)
Accounts payable		(72,532	)		(51,876	)		(1,512	)
Accrued taxes		6,847			629			(549	)
Accrued compensation		311			1,946			104
Other current liabilities		9,011			4,325			8,300
Net cash provided from operating activities		152,686			144,506			191,310
Investing Activities:
Property additions		(143,171	)		(148,765	)		(98,572	)
Cost of removal net of salvage		(8,504	)		(10,259	)		(7,881	)
Construction payables		(8,806	)		13,682			(2,726	)
Other		(440	)		8,952			(2,545	)
Net cash used for investing activities		(160,921	)		(136,390	)		(111,724	)
Financing Activities:
Increase in notes payable, net		39,465			12,334			9,187
Proceeds —
Pollution control bonds		—			—			61,625
Senior notes		60,000			110,000			225,000
Other long-term debt		—			100,000			—
Preferred and preference stock		55,000			—			—
Capital contributions from parent company		(94	)		29,481			13,315
Redemptions —
Pollution control bonds		—			—			(61,625	)
First mortgage bonds		(30,000	)		—			—
Senior notes		—			(125,000	)		(151,757	)
Other long-term debt		(100,000	)		—			(20,000	)
Preferred and preference stock		(4,236	)		—			—
Mandatorily redeemable preferred securities		—			—			(85,000	)
Payment of preferred and preference stock dividends		(761	)		(217	)		(217	)
Payment of common stock dividends		(68,400	)		(70,000	)		(70,200	)
Other		(3,721	)		(2,433	)		(10,644	)
Net cash provided from (used for) financing activities		(52,747	)		54,165			(90,316	)
Net Change in Cash and Cash Equivalents		(60,982	)		62,281			(10,730	)
Cash and Cash Equivalents at Beginning of Year		64,829			2,548			13,278
Cash and Cash Equivalents at End of Year	$	3,847		$	64,829		$	2,548
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $515, $819, and $314 capitalized, respectively)	$	35,786		$	28,796		$	37,468
Income taxes (net of refunds)		(27,912	)		24,130			23,777

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

II-209

BALANCE SHEETS
At December 31, 2005 and 2004
Gulf Power Company 2005 Annual Report

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

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

II-210

BALANCE SHEETS
At December 31, 2005 and 2004
Gulf Power Company 2005 Annual Report

Liabilities and Stockholder’s Equity	2005		2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	37,075	$	100,000
Notes payable		89,465		50,000
Accounts payable —
Affiliated		36,717		35,359
Other		44,139		77,452
Customer deposits		18,834		18,470
Accrued taxes —
Income taxes		12,823		1,927
Other		11,689		9,250
Accrued interest		7,713		7,665
Accrued compensation		20,336		16,989
Other regulatory liabilities		15,671		6,469
Other		21,844		13,179
Total current liabilities		316,306		336,760
Long-term Debt(See accompanying statements)		544,388		550,989
Long-term Debt Payable to Affiliated Trusts(See accompanying statements)		72,166		72,166
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		256,490		229,909
Accumulated deferred investment tax credits		16,569		18,489
Employee benefit obligations		56,235		54,869
Other cost of removal obligations		153,665		155,831
Other regulatory liabilities		26,795		25,402
Other		76,948		71,192
Total deferred credits and other liabilities		586,702		555,692
Total Liabilities		1,519,562		1,515,607
Preferred and Preference Stock(See accompanying statements)		53,891		4,098
Common Stockholder’s Equity(See accompanying statements)		602,344		592,172
Total Liabilities and Stockholder’s Equity	$	2,175,797	$	2,111,877
Commitments and Contingent Matters(See notes)

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

II-211

STATEMENTS OF CAPITALIZATION
At December 31, 2005 and 2004
Gulf Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long Term Debt:
First mortgage bonds —
6.50% due November 1, 2006	$	25,000		$	25,000
6.88% due January 1, 2026		—			30,000
Total first mortgage bonds		25,000			55,000
Long-term notes payable —
Variable rate (2.36% at 1/1/05) due October 28, 2005		—			100,000
4.35% to 5.88% due 2013-2044		395,000			335,000
Total long-term notes payable		395,000			435,000
Other long-term debt —
Pollution control revenue bonds —
Collateralized: 5.25% due April 1, 2006		12,075			12,075
Non-collateralized:
4.80% due September 1, 2028		13,000			13,000
Variable rates (3.10% to 3.80% at 1/1/06) due 2022-2037		144,555			144,555
Total other long-term debt		169,630			169,630
Unamortized debt premium (discount), net		(8,167	)		(8,641	)
Total long-term debt (annual interest requirement — $28.5 million)		581,463			650,989
Less amount due within one year		37,075			100,000
Long-term debt excluding amount due within one year		544,388			550,989			42.8	%		45.2	%
Long-term Debt Payable to Affiliated Trusts:
5.6% to 7.38% due 2041 through 2042 (annual interest requirement — $4.6 million)		72,166			72,166			5.7			5.9
Preferred and Preference Stock:
Cumulative preferred stock
$100 par value
Authorized — 10,000,000 shares
Outstanding — No shares in 2005, 42,361 shares in 2004 4.64% to 5.44%		—			4,098
Non-cumulative preference stock
$100 par or stated value — 6.00%
Authorized — 10,000,000 shares
Outstanding — 550,000 shares		53,891			—
Total preferred and preference stock (annual dividend requirement — $3.3 million)		53,891			4,098			4.2			0.3
Common Stockholder’s Equity:
Common stock, without par value —
Authorized — 10,000,000 shares
Outstanding — 992,717 shares		38,060			38,060
Paid-in capital		400,815			397,396
Retained earnings		166,279			159,581
Accumulated other comprehensive income (loss)		(2,810	)		(2,865	)
Total common stockholder’s equity		602,344			592,172			47.3			48.6
Total Capitalization	$	1,272,789		$	1,219,425			100.0	%		100.0	%

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

II-212

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

For the Years Ended December 31, 2005, 2004, and 2003

Gulf Power Company 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
	(in thousands)
Balance at December 31, 2002	$	38,060	$	349,781		$	162,398		$	(734	)	$	549,505
Net income after dividends on preferred stock		—		—			69,010			—			69,010
Capital contributions from parent company		—		15,083			—			—			15,083
Other comprehensive income (loss)		—		—			—			(2,040	)		(2,040	)
Cash dividends on common stock		—		—			(70,200	)		—			(70,200	)
Balance at December 31, 2003		38,060		364,864			161,208			(2,774	)		561,358
Net income after dividends on preferred stock		—		—			68,223			—			68,223
Capital contributions from parent company		—		32,544			—			—			32,544
Other comprehensive income (loss)		—		—			—			(91	)		(91	)
Cash dividends on common stock		—		—			(70,000	)		—			(70,000	)
Other		—		(12	)		150			—			138
Balance at December 31, 2004		38,060		397,396			159,581			(2,865	)		592,172
Net income after dividends on preferred and preference stock		—		—			75,209			—			75,209
Capital contributions from parent company		—		3,408			—			—			3,408
Other comprehensive income (loss)		—		—			—			55			55
Cash dividends on common stock		—		—			(68,400	)		—			(68,400	)
Other		—		11			(111	)		—			(100	)
Balance at December 31, 2005	$	38,060	$	400,815		$	166,279		$	(2,810	)	$	602,344

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

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2005, 2004, and 2003

Gulf Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Net income after dividends on preferred and preference stock	$	75,209		$	68,223		$	69,010
Other comprehensive income (loss):
Changes in additional minimum pension liability, net of tax of $(91), $(184) and $(84), respectively		(146	)		(292	)		(134	)
Change in fair value of marketable securities, net of tax of $35		—			56			—
Changes in fair value of qualifying hedges, net of tax of $(1,260)		—			—			(2,006	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $126, $91 and $63		201			145			100
Total other comprehensive income (loss)		55			(91	)		(2,040	)
Comprehensive Income	$	75,264		$	68,132		$	66,970

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

II-213

NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Gulf Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies, Alabama Power, Georgia Power, the Company, Mississippi Power, and Savannah Electric, provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing service to customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power, related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power, are regulated by the Federal Energy Regulatory Commission (FERC). SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

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

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Florida Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $54 million, $56 million, and $55 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, and management believes they are reasonable.

     The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $4.3 million, $6.8 million, and $4.9 million and Mississippi Power $18.4 million, $17.8 million, and $17.7 million in 2005, 2004, and 2003, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information.

     The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in the last two years, assistance provided to aid in storm restoration, including Company labor, contract labor, and materials, has caused an increase in

II-214

NOTES (continued)
Gulf Power Company 2005 Annual Report

these activities. The total amount of storm restoration provided to Mississippi Power in 2005 was $11.1 million. These activities were billed at cost. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $5.8 million and $12.7 million in 2005 and 2004, respectively.

     The retail operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.

Regulatory Assets and Liabilities

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

	2005			2004			Note
	(in thousands)
Environmental remediation	$	58,235		$	59,364			(a	)
Loss on reacquired debt		19,433			19,197			(b	)
Vacation pay		5,662			5,446			(c	)
Deferred income tax charges		17,379			17,566			(d	)
Fuel-hedging assets		2,411			1,685			(e	)
Other assets		3,374			5,656			(f	)
Under recovered regulatory clause revenues		31,634			7,931			(f	)
Property damage recovery		30,778			—			(g	)
Property damage reserve		43,574			48,284			(f	)
Asset retirement obligations		(640	)		1,453			(d	)
Other cost of removal obligations		(153,665	)		(155,831	)		(d	)
Deferred income tax credits		(20,627	)		(23,354	)		(d	)
Fuel-hedging liabilities		(13,950	)		(1,994	)		(e	)
Over recovered regulatory clause revenues		(5,333	)		(4,554	)		(f	)
Other liabilities		(1,916	)		(1,967	)		(f	)
Total	$	16,349		$	(21,118	)

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

(a)	Recovered through the environmental cost recovery clause when the expense is incurred.
(b)	Recovered over the remaining life of the original issue, which may range up to 40 years.
(c)	Recorded as earned by employees and recovered as paid, generally within one year.
(d)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
(f)	Recorded and recovered or amortized as approved by the Florida PSC.
(g)	Recorded and recovered over 24 months ending March 2007 as approved by the Florida PSC.

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

Revenues

Energy and other revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Capacity revenues are generally recognized on a levelized basis over the appropriate contract period. The Company’s retail electric rates include provisions to annually adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. If the projected fuel revenue over or under recovery exceeds 10 percent of the projected fuel costs for the period, the Company is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of

II-215

NOTES (continued)
Gulf Power Company 2005 Annual Report

projected costs including any true-up amount from prior periods, and approved rates are implemented each January.

     The Company has a diversified base of customers and no single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts averaged significantly less than 1 percent of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used.

Income Taxes

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

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits, and the interest capitalized and/or estimated cost of funds used during construction. The Company’s property, plant, and equipment consisted of the following at December 31:

	2005		2004
	(in thousands)
Generation	$	1,326,766	$	1,237,184
Transmission		262,168		254,506
Distribution		788,711		754,667
General		120,339		116,503
Plant acquisition adjustment		4,073		4,329
Total plant in service	$	2,502,057	$	2,367,189

     The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred or performed.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.8 percent in each of 2005, 2004, and 2003. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to the accumulated provision for depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations, which established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The present value of the ultimate cost for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. The Company has received accounting guidance from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or Interpretation No. 47.

     The liability recognized to retire long-lived assets primarily relates to the Company’s combustion turbines at its Pea Ridge facility, various landfill sites, and a barge unloading dock. In connection with the adoption of Interpretation of No. 47, the Company has also recorded additional asset retirement obligations (and

II-216

NOTES (continued)
Gulf Power Company 2005 Annual Report

assets) of $9.1 million, primarily related to asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company has also identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets.

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

	2005		2004
	(in thousands)
Balance beginning of year	$	5,789	$	4,271
Liabilities incurred		9,122		—
Liabilities settled		—		—
Accretion		387		316
Cash flow revisions		—		1,202
Balance end of year	$	15,298	$	5,789

     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $14.3 million.

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC on certain construction projects. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. For the years 2005, 2004, and 2003, the average annual AFUDC rate was 7.48 percent. AFUDC, net of taxes, as a percentage of net income after dividends on preferred and preference stock was 1.97 percent, 3.46 percent, and 1.31 percent, respectively, for 2005, 2004, and 2003.

Impairment of Long-Lived Assets and Intangibles

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

Property Damage Reserve

The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The cost of such damages is charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $25.1 million and $36.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company’s discretion. The Company accrued total expenses of $9.5 million in 2005, $18.5 million in 2004, and $10.6 million in 2003. At December 31, 2005, the deficit balance in the property damage reserve was $43.6 million, of which approximately $3.5 million and $40.1 million is included in Current Assets and Deferred Charges and Other Assets, respectively, in the balance sheets. See Note 3 under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information regarding the depletion of these reserves following Hurricanes Ivan, Dennis, and Katrina, and the deferral of additional costs, as well as additional surcharges or other cost recovery mechanisms approved by the Florida PSC to replenish these reserves.

Environmental Cost Recovery

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company

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may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually each January. In September 2004, the Company increased its liability for the estimated costs of environmental remediation projects by approximately $47 million. This increase related to new regulations and more stringent site closure criteria by the Florida Department of Environmental Protection (FDEP) for impacts to soil and groundwater from herbicide applications at company substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery, as expended, through the Company’s environmental cost recovery clause; therefore, there was no impact on the Company’s net income as a result of these revised estimates. The liability balances as of December 31, 2005 and 2004 were $58.2 million and $59.4 million, respectively. See Note 3 under “Retail Regulatory Matters – Environmental Remediation” for additional information.

Injuries and Damages Reserve

The Company is subject to claims and suits arising in the ordinary course of business. As permitted by regulatory authorities, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. At both December 31, 2005 and 2004, the injuries and damages reserve was $1.7 million and is included in Current Liabilities in the balance sheets. Liabilities in excess of the reserve balance of $3.0 million and $4.8 million at December 31, 2005 and 2004, respectively, are included in Deferred Credits and Other Liabilities in the balance sheets. Corresponding regulatory assets of $1.6 million at both December 31, 2005 and 2004 are included in Current Assets in the balance sheets. At December 31, 2005 and 2004, respectively, $1.4 million and $3.2 million are included in Deferred Charges and Other Assets in the balance sheets.

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, and natural gas. Fuel is charged to inventory when purchased and then expensed as used.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.

     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on net income is as follows:

	As		Options			Pro
	Reported		Impact			Forma
	(in thousands)
2005	$	75,209	$	(586	)	$	74,623
2004		68,223		(522	)		67,701
2003		69,010		(593	)		68,417

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     The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:

	2005			2004			2003
Interest rate		3.9	%		3.1	%		2.7	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.9	%		19.6	%		23.6	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

Financial Instruments

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

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

     Other financial instruments for which the carrying amount does not equal fair value at December 31 were as follows:

	Carrying		Fair
	Amount		Value
	(in thousands)
Long-term debt:
2005	$	653,629	$	644,677
2004		723,155		729,821

     The fair values were based on either closing market price or closing price of comparable instruments.

Comprehensive Income

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

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established certain wholly-owned trusts to issue preferred securities. However, the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments for the Company, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees.

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Benefits under these non-qualified plans are funded on a cash basis. The Company provides certain medical care and life insurance benefits for retired employees. In addition, trusts are funded to the extent required by the Florida PSC and the FERC. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately $70,000.

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

Pension Plans

The total accumulated benefit obligation for the pension plans was $226 million in 2005 and $204 million in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

	Projected
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	228,414		$	206,486
Service cost		6,318			5,915
Interest cost		12,866			12,136
Benefits paid		(10,081	)		(9,499	)
Actuarial (gain)/loss and employee transfers, net		10,509			13,376
Balance at end of year	$	248,026		$	228,414

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	250,238		$	236,345
Actual return on plan assets		38,478			23,152
Employer contributions		732			550
Benefits paid		(10,081	)		(9,499	)
Employee transfers		999			(310	)
Balance at end of year	$	280,366		$	250,238

     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $236 million and $12 million, respectively. All plan assets are related to the qualified plan.

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

	Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	Accrued Pension Costs
	2005			2004
	(in thousands)
Funded status	$	32,340		$	21,824
Unrecognized transition amount		—			(721	)
Unrecognized prior service cost		12,780			12,434
Unrecognized net (gain)/loss		(3,645	)		7,511
Prepaid pension asset, net	$	41,475		$	41,048

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

	2005			2004
	(in thousands)
Prepaid pension asset	$	46,374		$	45,384
Employee benefit obligations		(7,893	)		(7,316	)
Other property and investments — other		868			1,091
Accumulated other comprehensive income		2,126			1,889
Prepaid pension asset, net	$	41,475		$	41,048

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

	2005			2004			2003
	(in thousands)
Service cost	$	6,317		$	5,915		$	5,225
Interest cost		12,866			12,136			11,733
Expected return on plan assets		(20,816	)		(20,689	)		(20,564	)
Recognized net (gain)/loss		350			(317	)		(1,819	)
Net amortization		502			486			486
Net pension income	$	(781	)	$	(2,469	)	$	(4,939	)

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	Benefit
	Payments
	(in thousands)
2006	$	10,459
2007		10,756
2008		11,053
2009		11,403
2010		11,895
2011 to 2015	$	69,865

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

	Accumulated
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	69,186		$	72,903
Service cost		1,357			1,275
Interest cost		3,892			4,080
Benefits paid		(3,124	)		(2,447	)
Actuarial (gain)/loss		1,969			(6,625	)
Balance at end of year	$	73,280		$	69,186

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	14,296		$	12,642
Actual return on plan assets		2,114			1,594
Employer contributions		3,148			2,507
Benefits paid		(3,124	)		(2,447	)
Balance at end of year	$	16,434		$	14,296

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

	Plan Assets
	Target			2005			2004
Domestic equity		34	%		38	%		34	%
International equity		23			23			19
Fixed income		19			21			30
Real estate		14			12			10
Private equity		10			6			7
Total		100	%		100	%		100	%

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

	2005			2004
	(in thousands)
Funded status	$	(56,846	)	$	(54,891	)
Unrecognized transition obligation		2,589			2,944
Unrecognized prior service cost		4,311			4,657
Unrecognized net (gain)/loss		9,026			8,074
Fourth quarter contributions		973			829
Accrued liability recognized in the balance sheets	$	(39,947	)	$	(38,387	)

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

	2005			2004			2003
	(in thousands)
Service cost	$	1,357		$	1,275		$	1,128
Interest cost		3,892			4,081			4,058
Expected return on plan assets		(1,202	)		(1,220	)		(1,139	)
Transition obligation		356			355			356
Prior service cost		346			346			346
Recognized net (gain)/loss		33			241			113
Net postretirement cost	$	4,782		$	5,078		$	4,862

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to

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the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $0.5 million and $1.1 million, respectively, and is expected to have a similar impact on future years.

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

	Benefit		Subsidy
	Payments		Receipts			Total
			(in thousands)
2006	$	3,628	$	(315	)	$	3,313
2007		3,803		(399	)		3,404
2008		4,146		(456	)		3,690
2009		4,518		(508	)		4,010
2010		4,881		(558	)		4,323
2011 to 2015	$	27,109	$	(3,936	)	$	23,173

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:

	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00	%		3.50	%		3.75	%
Long-term return on plan assets		8.50	%		8.50	%		8.50	%

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows:

	1 Percent
	Increase		Decrease
	(in thousands)
Benefit obligation	$	4,745	$	4,254
Service and interest costs	$	310	$	276

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003, were $2.9 million, $2.7 million, and $2.6 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.

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Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plant Crist and a unit partially owned by the Company at Plant Scherer. See Note 4 herein for information on the Company’s ownership interest in Plant Scherer Unit 3. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in the notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled.

     On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.

     The Company believes that it complied with applicable laws and the EPA’s regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a

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result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, the Company, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, including the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund amounts previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC. The Company has received similar requests from other entities totaling $6.7 million. The Company has opposed all such requests. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including the Company, Georgia Power, Mississippi Power, and Southern Telecom (collectively, defendants), have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties, and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief. The Company’s management believe that it has complied with applicable laws and that the plaintiffs’ claims are without merit.

     In November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over the Company’s rights of way located on the landowners’ property. Subsequently, the plaintiffs sought to amend their complaint and asked

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the court to enter a final declaratory judgment and to enter an order enjoining the Company from allowing expanded general telecommunications use of the fiber optic cables that are the subject of this litigation. In January 2005, the trial court granted in part the plaintiffs’ motion to amend their complaint and denied the requested declaratory and injunctive relief. In November 2005, the trial court ruled in favor of the plaintiffs and against the Company on their respective motions for partial summary judgment. In that same order, the trial court also denied the Company’s motion to dismiss certain claims. The court’s ruling allowed for an immediate appeal to the Florida First District Court of Appeal, which the Company filed on December 20, 2005. If the appeal is not successful, damages will be decided at a future trial.

     In addition, in late 2001, certain subsidiaries of Southern Company, including the Company, Alabama Power, Georgia Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively, defendants), were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The defendants believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Property Tax Dispute

Georgia Power and the Company are involved in a significant property tax dispute with Monroe County, Georgia (Monroe County). The Monroe County Board of Tax Assessors (Monroe Board) has issued assessments reflecting substantial increases in the ad valorem tax valuation of Plant Scherer, of which Georgia Power and the Company own 22.95 percent and 6.25 percent, respectively, for tax years 2003, 2004, and 2005. Georgia Power and the Company are aggressively pursuing administrative appeals in Monroe County and have filed or will file Notices of Arbitration for all three years. The appeals are currently stayed, pending the outcome of the litigation discussed below.

     In addition, in November 2004, Georgia Power filed suit, on its own behalf, against the Monroe Board in the Superior Court of Monroe County. The suit could impact all co-owners. Georgia Power contends that Monroe County acted without statutory authority in changing the valuation of a centrally assessed utility as established by the Revenue Commissioner of the State of Georgia and requests injunctive relief prohibiting Monroe County and the Monroe Board from unlawfully changing the value of Plant Scherer and ultimately collecting additional ad valorem taxes from Georgia Power. On December 22, 2005, the Court granted Monroe County’s motion for summary judgment. Georgia Power has filed an appeal of the Superior Court’s decision to the Georgia Supreme Court.

     If Georgia Power is not successful in its administrative appeals and if Monroe County is successful in defending the litigation, the Company could be subject to total additional taxes through December 31, 2005 of up to $3 million, plus penalties and interest. In accordance with the Company’s unit power sales contract for Plant Scherer, such property taxes would be recoverable from the customer. The final outcome of this matter cannot now be determined.

Retail Regulatory Matters

Environmental Cost Recovery

The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operation and maintenance expense, emission allowance expense, depreciation, and a return on invested capital. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. During 2005, 2004, and 2003, the Company recorded environmental cost recovery clause revenues of $26.3 million, $14.7 million, and $10.9 million, respectively. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At

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NOTES (continued)
Gulf Power Company 2005 Annual Report

December 31, 2005, the over recovered balance was $3.0 million primarily due to a delay in environmental projects.

Environmental Remediation

At December 31, 2005, the Company’s liability for the estimated costs of environmental remediation projects for known sites was $58.2 million. The schedule for completion of the remediation projects will be subject to FDEP approval. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause. Therefore, the Company has recorded $1.6 million in Current Assets and Current Liabilities and $56.6 million in Deferred Charges and Other Assets and Deferred Credits and Other Liabilities representing the future recoverability of these costs.

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

Storm Damage Cost Recovery

The Company maintains a reserve to recover the cost of uninsured damages from major storms to its transmission and distribution facilities, generation facilities, and other property.

     Hurricane Ivan hit the Gulf Coast of Florida and Alabama in September 2004, causing significant damage to the Company’s service territory. In March 2005, the Florida PSC approved a Stipulation and Settlement (Stipulation) among the Company, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group. The agreement allows the Company to recover the retail portion of $51.7 million in storm damage costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. As of December 31, 2005, the Company had recovered $21.2 million of these costs. Under the Stipulation, the Company also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused additional damage in the Company’s service area. Hurricanes Dennis and Katrina restoration costs were approximately $64 million, of which approximately $56 million relates to operation and maintenance expenses. Approximately $1 million of these costs is expected to be covered through insurance.

     As of December 31, 2005, the deficit balance in the Company’s property damage reserve accounts totaled approximately $43.6 million, of which approximately $3.5 million and $40.1 million, respectively, is included in the balance sheets under Current Assets and Deferred Charges and Other Assets. The established policy of the Florida PSC, as recently reaffirmed by its decision following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for the recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge.

     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, the Company filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over eight years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve the Company’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish the Company’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. The final outcome of these matters cannot now be determined; however, since the Company will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on the Company’s net income, but would increase cash flow.

     See Note 1 herein under “Property Damage Reserve” for additional information.

4. JOINT OWNERSHIP AGREEMENTS

The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 megawatt (MW). Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company’s agent with respect to the construction, operation, and maintenance of these units.

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Gulf Power Company 2005 Annual Report

     The Company and Georgia Power jointly own the 818 MW capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company’s agent with respect to the construction, operation, and maintenance of the unit.

     The Company’s pro rata share of expenses related to both plants is included in the corresponding operating expense accounts in the statements of income.

     At December 31, 2005, the Company’s percentage ownership and its investment in these jointly owned facilities were as follows:

	Plant			Plant
	Scherer			Daniel
	Unit 3			Units 1 & 2
	(coal)			(coal)
	(in thousands)
Plant in service	$	190,534	(1)	$	244,380
Accumulated depreciation		87,817			133,923
Construction work in progress		360			3,620
Ownership		25	%		50	%

(1) Includes net plant acquisition adjustment of $4.1 million.

5. INCOME TAXES

Southern Company and its subsidiaries file a consolidated federal income tax return and combined State of Mississippi and State of Georgia income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

     At December 31, 2005, the tax-related regulatory assets to be recovered from customers were $17.4 million. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized allowance for funds used during construction. At December 31, 2005, the tax-related regulatory liabilities to be credited to customers were $20.6 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.

     Details of income tax provisions are as follows:

	2005		2004			2003
	(in thousands)
Federal —
Current	$	11,330	$	(4,255	)	$	33,871
Deferred		26,693		39,373			1,702
		38,023		35,118			35,573
State —
Current		490		(2,305	)		4,703
Deferred		6,468		6,882			601
		6,958		4,577			5,304
Total	$	44,981	$	39,695		$	40,877

     The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in thousands)
Deferred tax liabilities:
Accelerated depreciation	$	245,906		$	218,137
Fuel recovery clause		12,812			3,212
Pension benefits		14,817			14,176
Property reserve		29,393			20,675
Other		6,352			15,029
Total		309,280			271,229
Deferred tax assets:
Federal effect of state deferred taxes		13,591			11,930
Postretirement benefits		13,430			12,588
Pension benefits		2,054			2,020
Other comprehensive loss		1,765			1,800
Other		13,082			11,055
Total		43,922			39,393
Net deferred tax liabilities		265,358			231,836
Less current portion, net		(8,868	)		(1,927	)
Accumulated deferred income taxes in the balance sheets	$	256,490		$	229,909

     In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Credits amortized in this manner amounted to $1.9 million in 2005, $2.0 million in 2004, and $1.8 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

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NOTES (continued)
Gulf Power Company 2005 Annual Report

     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2005			2004			2003
Federal statutory rate		35	%		35	%		35	%
State income tax, net of federal deduction		4			3			3
Non-deductible book depreciation		1			1			1
Difference in prior years’ deferred and current tax rate		(1	)		(1	)		(1	)
Other, net		(2	)		(1	)		(1	)
Effective income tax rate		37	%		37	%		37	%

6. FINANCING

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

The Company has formed certain wholly owned trust subsidiaries for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $72.2 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trusts. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trusts’ payment obligations with respect to these securities. At December 31, 2005, $72.2 million of these securities were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $12.1 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the loan agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the loan agreements.

Securities Due Within One Year

At December 31, 2005, the Company had an improvement fund requirement of $250,000. The first mortgage bond improvement fund requirement amounts to 1 percent of each outstanding series of bonds authenticated under the mortgage indenture prior to January 1 of each year, other than those issued to collateralize pollution control revenue bond obligations. The requirement may be satisfied by depositing cash, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times the requirement. The improvement fund requirements of first mortgage bonds were satisfied by certifying property additions in 2004 and 2003. It is anticipated that the 2005 requirement will be satisfied by certifying property additions.

     The Company’s remaining first mortgage bonds mature in 2006; therefore, the only sinking fund requirements and/or maturities through 2010 are $37.1 million in 2006.

Assets Subject to Lien

The Company’s mortgage indenture dated as of September 1, 1941, as amended and supplemented, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company’s fixed property and franchises. In connection with the maturity of the Company’s remaining outstanding first mortgage bonds in November 2006, such lien will be removed. In addition, the Company has granted a second lien on its property at Plant Daniel in connection with the issuance of one series of pollution control bonds.

     There are no agreements or other arrangements among the affiliated companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries.

Bank Credit Arrangements

At the beginning of 2006, the Company had $120.5 million of lines of credit with banks subject to renewal each year, all of which remained unused. Of the $120.5 million, $116.5 million provides liquidity support for the Company’s commercial paper program and $4.0 million of daily variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees.

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NOTES (continued)
Gulf Power Company 2005 Annual Report

     Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the arrangements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts. At December 31, 2005, the Company was in compliance with these covenants.

     In addition, certain credit arrangements contain cross default provisions to other indebtedness that would trigger an event of default if the Company defaulted on indebtedness over a specified threshold. The cross default provisions are restricted only to indebtedness of the Company. The Company is currently in compliance with all such covenants. Borrowings under unused credit arrangements totaling $10 million would be prohibited if the Company experiences a material adverse change (as defined in such arrangements).

     The Company borrows primarily through a commercial paper program that has the liquidity support of committed bank credit arrangements. The Company may also borrow through various other arrangements with banks and through an extendible commercial note program. At December 31, 2005, the Company had $89.5 million in commercial paper and bank notes outstanding. At December 31, 2004, the Company had no commercial paper or extendible commercial notes outstanding. During 2005, the peak amount outstanding for commercial paper was $110 million and the average amount outstanding was $51.8 million. The average annual interest rate on commercial paper was 3.56 percent.

Financial Instruments

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs with the approval of the Florida PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005 and 2004.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	11,540
Other comprehensive income		—
Net income		(14	)
Total fair value	$	11,526

     The fair value gains or losses for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2008.

     The Company also may enter into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges and are generally structured to match the critical terms of the hedged debt instruments.

     The Company had no interest rate derivatives outstanding in 2005 or 2004. During 2003, the Company settled interest rate derivatives at the same time it issued debt and recognized losses totaling $3.3 million. These losses have been deferred in other comprehensive income and approximately $0.3 million annually is reclassified to interest expense over the life of the related debt, which matures in 2013.

7. COMMITMENTS

Construction Program

The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $163 million in 2006, $221 million in 2007, and $221 million in 2008. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generation assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the ongoing construction program.

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NOTES (continued)
Gulf Power Company 2005 Annual Report

     Included in the amounts above, are $48 million in 2006, $131 million in 2007, and $141 million in 2008 for environmental expenditures. The Company does not have any new generating capacity under construction. Construction of new transmission and distribution facilities and other capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, are ongoing.

Long-Term Service Agreements

The Company has a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for combined cycle and combustion turbine generating facilities. The LTSA provides that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract.

     In general, the LTSA is in effect through two major inspection cycles of the unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the unit. Total payments to GE under this agreement for facilities owned are currently estimated at $78.1 million over the remaining life of the agreement. However, the LTSA contains various cancellation provisions at the option of the Company.

     Payments made to GE prior to the performance of any planned inspections are recorded as prepayments. These amounts are included in Current Assets and Deferred Charges and Other Assets in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

Fuel Commitments

To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005.

     Total estimated minimum long-term obligations at December 31, 2005 were as follows:

	Natural
Year	Gas		Coal
	(in thousands)
2006	$	123,447	$	240,647
2007		71,482		92,694
2008		45,201		—
2009		18,886		—
2010		18,886		—
2011 and thereafter		204,030		—
Total commitments	$	481,932	$	333,341

     Additional commitments for fuel will be required to supply the Company’s future needs.

     SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company Gas. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company Gas as a contracting party under these agreements.

Operating Leases

The Company has operating lease agreements with various terms and expiration dates. Total operating lease expenses were $3.0 million, $2.0 million, and $2.2 million for 2005, 2004, and 2003, respectively. The Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term.

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NOTES (continued)
Gulf Power Company 2005 Annual Report

     At December 31, 2005, estimated minimum rental commitments for noncancelable operating leases were as follows:

	Rail
Year	Cars		Other		Total
	(in thousands)
2006	$	4,816	$	59	$	4,875
2007		4,105		61		4,166
2008		3,134		63		3,197
2009		2,101		—		2,101
2010		2,068		—		2,068
2011 and thereafter		4,170		—		4,170
Total minimum payments	$	20,394	$	183	$	20,577

     The Company and Mississippi Power jointly entered into operating lease agreements for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options.

     These railcar lease costs are charged to fuel inventory and are allocated to fuel expense as the fuel is used. These expenses are then recovered through the Company’s fuel cost recovery clause. The Company’s share of the lease costs charged to fuel inventories was $3.0 million in 2005 and $1.9 million in each of 2004 and 2003.

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of its employees ranging from line management to executives. As of December 31, 2005, 269 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan.

     Activity for 2003 through 2005 for the options granted to the Company’s employees under the stock option plan is summarized below:

	Shares			Average
	Subject			Option Price
	to Option			per Share
Balance at December 31, 2002		1,226,198		$	19.88
Options granted		274,245			27.98
Options canceled		(3,082	)		19.26
Options exercised		(192,189	)		17.01
Balance at December 31, 2003		1,305,172			22.00
Options granted		256,363			29.50
Options canceled		(438	)		28.47
Options exercised		(386,413	)		18.76
Balance at December 31, 2004		1,174,684			24.70
Options granted		249,683			32.70
Options canceled		(2,131	)		29.08
Options exercised		(322,687	)		22.80
Balance at December 31, 2005		1,099,549		$	27.07
Options exercisable:
At December 31, 2003		839,618
At December 31, 2004		715,570
At December 31, 2005		622,435

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares (in thousands)		158		452		490
Average remaining life (in years)		4.2		6.3		8.6
Average exercise price	$	17.11	$	26.13	$	31.13
Exercisable:
Shares (in thousands)		158		381		84
Average exercise price	$	17.11	$	25.79	$	29.67

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NOTES (continued)
Gulf Power Company 2005 Annual Report

9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2005 and 2004 are as follows:

					Net Income
					After Dividends
	Operating		Operating		on Preferred and
Quarter Ended	Revenues		Income		Preference Stock
	(in thousands)
March 2005	$	224,597	$	31,229	$	14,646
June 2005		251,297		44,153		21,458
September 2005		344,080		68,571		37,197
December 2005		263,648		14,324		1,908
March 2004	$	214,919	$	35,803	$	16,839
June 2004		241,170		39,824		19,002
September 2004		269,386		59,628		31,900
December 2004		234,656		9,457		482

     The Company’s business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Gulf Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands)	$	1,083,622	$	960,131	$	877,697	$	820,467	$	725,203
Net Income after Dividends on Preferred and Preference Stock (in thousands)	$	75,209	$	68,223	$	69,010	$	67,036	$	58,307
Cash Dividends on Common Stock (in thousands)	$	68,400	$	70,000	$	70,200	$	65,500	$	53,275
Return on Average Common Equity (percent)		12.59		11.83		12.42		12.72		12.51
Total Assets (in thousands)	$	2,175,797	$	2,111,877	$	1,839,053	$	1,816,889	$	1,713,436
Gross Property Additions (in thousands)	$	142,583	$	161,205	$	99,284	$	106,624	$	274,668
Capitalization (in thousands) :
Common stock equity	$	602,344	$	592,172	$	561,358	$	549,505	$	504,894
Preferred and preference stock		53,891		4,098		4,236		4,236		4,236
Mandatorily redeemable preferred securities		—		—		70,000		115,000		115,000
Long-term debt payable to affiliated trusts		72,166		72,166		—		—		—
Long-term debt		544,388		550,989		515,827		452,040		467,784
Total (excluding amounts due within one year)	$	1,272,789	$	1,219,425	$	1,151,421	$	1,120,781	$	1,091,914
Capitalization Ratios (percent) :
Common stock equity		47.3		48.6		48.8		49.0		46.2
Preferred and preference stock		4.2		0.3		0.4		0.4		0.4
Mandatorily redeemable preferred securities		—		—		6.1		10.3		10.5
Long-term debt payable to affiliated trusts		5.7		5.9		—		—		—
Long-term debt		42.8		45.2		44.7		40.3		42.9
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
First Mortgage Bonds —
Moody’s		A1		A1		A1		A1		A1
Standard and Poor’s		A+		A+		A+		A+		A+
Fitch		A+		A+		A+		A+		A+
Preferred Stock/ Preference Stock —
Moody’s	Baa1		Baa1		Baa1		Baa1		Baa1
Standard and Poor’s	BBB+		BBB+		BBB+		BBB+		BBB+
Fitch		A-		A-		A-		A-		A-
Unsecured Long-Term Debt —
Moody’s		A2		A2		A2		A2		A2
Standard and Poor’s		A		A		A		A		A
Fitch		A		A		A		A		A
Customers (year-end) :
Residential		354,466		343,151		341,935		333,757		327,128
Commercial		53,398		51,865		51,169		49,411		48,654
Industrial		298		285		285		281		270
Other		479		473		473		474		468
Total		408,641		395,774		393,862		383,923		376,520
Employees(year-end)		1,335		1,336		1,337		1,339		1,309

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Gulf Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands) :
Residential	$	465,346	$	401,382	$	381,464	$	365,693	$	313,165
Commercial		273,114		232,928		218,928		207,960		188,759
Industrial		123,044		99,420		95,702		89,385		81,719
Other		3,355		3,140		3,080		2,798		948
Total retail		864,859		736,870		699,174		665,836		584,591
Sales for resale — non-affiliates		84,346		73,537		76,767		77,171		82,252
Sales for resale — affiliates		91,352		110,264		63,268		40,391		27,256
Total revenues from sales of electricity		1,040,557		920,671		839,209		783,398		694,099
Other revenues		43,065		39,460		38,488		37,069		31,104
Total	$	1,083,622	$	960,131	$	877,697	$	820,467	$	725,203
Kilowatt-Hour Sales (in thousands) :
Residential		5,319,630		5,215,332		5,101,099		5,143,802		4,716,404
Commercial		3,735,776		3,695,471		3,614,255		3,552,931		3,417,427
Industrial		2,160,760		2,113,027		2,146,956		2,053,668		2,018,206
Other		22,730		22,579		22,479		21,496		21,208
Total retail		11,238,896		11,046,409		10,884,789		10,771,897		10,173,245
Sales for resale — non-affiliates		2,295,850		2,256,942		2,504,211		2,156,741		2,093,203
Sales for resale — affiliates		1,976,368		3,124,788		2,438,874		1,720,240		962,892
Total		15,511,114		16,428,139		15,827,874		14,648,878		13,229,340
Average Revenue Per Kilowatt-Hour (cents) :
Residential		8.75		7.70		7.48		7.11		6.64
Commercial		7.31		6.30		6.06		5.85		5.52
Industrial		5.69		4.71		4.46		4.35		4.05
Total retail		7.70		6.67		6.42		6.18		5.75
Sales for resale		4.11		3.42		2.83		3.03		3.58
Total sales		6.71		5.60		5.30		5.35		5.25
Residential Average Annual Kilowatt-Hour Use Per Customer		15,181		15,096		15,064		15,510		14,497
Residential Average Annual Revenue Per Customer	$	1,328	$	1,162	$	1,126	$	1,100	$	963
Plant Nameplate Capacity Ratings (year-end) (megawatts)		2,712		2,712		2,786		2,809		2,188
Maximum Peak-Hour Demand (megawatts) :
Winter		2,124		2,061		2,494		2,182		2,106
Summer		2,433		2,421		2,269		2,454		2,223
Annual Load Factor (percent)		57.7		57.1		54.6		55.3		57.5
Plant Availability Fossil-Steam (percent)		89.7		92.4		90.7		90.6		90.1
Source of Energy Supply (percent) :
Coal		79.7		77.9		78.7		69.8		81.2
Gas		13.1		14.4		11.9		15.5		1.0
Purchased power —
From non-affiliates		2.8		4.5		3.2		4.6		6.5
From affiliates		4.4		3.2		6.2		10.1		11.3
Total		100.0		100.0		100.0		100.0		100.0

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MISSISSIPPI POWER COMPANY

FINANCIAL SECTION

II-235

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Mississippi Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements (pages II-257 to II-283) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power Company 2005 Annual Report

OVERVIEW

Business Activities

Mississippi Power Company (Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and to wholesale customers in the Southeast.

     Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These include costs related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration following Hurricane Katrina.

     Hurricane Katrina hit on August 29, 2005, causing substantial damage to the Company’s service territory as the worst natural disaster in the Company’s history. All of the Company’s 195,000 customers were without service immediately after the storm. Through a co-coordinated effort with Southern Company, as well as non-affiliates, the Company restored power to all who could receive it within twelve days. However, 19,200 customers remained unable to receive service as of December 31, 2005. The Company expects further rate proceedings in 2006 to recover the estimated $277 million in costs related to Hurricane Katrina and replenishment of the Company’s storm damage reserve. In 2004, the Company completed a successful retail rate proceeding designed to help provide future earnings stability. Appropriately balancing environmental expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future.

     In December 2005, the Company made its annual Performance Evaluation Plan (PEP) filing for the projected 2006 test period and requested a 5 percent increase in total retail revenues or $32 million increase in retail base revenues.

Key Performance Indicators

In striving to maximize shareholder value while providing cost effective energy to customers, the Company’s management continues to focus on several key indicators. These indicators are used to measure the Company’s performance for customers and employees. Recognizing the critical role in the Company’s success played by the Company employees, employee-related measures are a significant management focus. These measures include diversity and safety. The 2005 performance was at or above target for each of these employee performance standards. In recognition that the Company’s long-term financial success is dependent upon how well it satisfies its customers’ needs, the Company’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to the Company’s allowed return. PEP measures the Company’s performance on a 10 point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40 percent); service reliability, measured in outage minutes per customer (40 percent); and customer satisfaction, measured in surveys of residential customers (20 percent). The Company’s PEP performance score in 2005 was 8.44 out of 10, resulting in an 84 basis point increase to the Company’s retail allowed return on investment for 2006. See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” for more information on PEP.

     In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Management uses customer satisfaction surveys to evaluate the Company’s results. Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance excludes the impact of Hurricane Katrina. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

     The Company’s 2005 results compared with its targets for some of these key indicators are reflected in the following chart.

	2005		2005
Key Performance	Target		Actual
Indicator	Performance		Performance
Customer Satisfaction	Top quartile in customer surveys		Top quartile
Plant Availability- Peak Season EFOR	3.0% or less			1.51	%*
Net Income (in millions)	$	77.8	$	73.8

* Excludes effects of Hurricane Katrina. Including Hurricane Katrina EFOR was 15.14%.

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The Company’s performance in 2005 reflects the focus that management places on all of these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

Earnings

The Company’s net income after dividends on preferred stock was $73.8 million in 2005 compared to $76.8 million in 2004. The decrease in 2005 is primarily due to a $15.7 million decrease in retail base revenue due to the loss of customers as a result of Hurricane Katrina. Non-fuel related expenses increased $2.5 million primarily resulting from increased employee benefit expenses. Depreciation and amortization expenses decreased by $5.8 million due to the amortization of a regulatory liability related to Plant Daniel capacity, other revenues increased $1.2 million, wholesale base revenues increased $3.3 million, and dividends on preferred stock decreased $2.0 million as compared to 2004 as a result of the loss on redemption of preferred stock recognized in the third quarter of 2004.

     The net income after dividends on preferred stock of $76.8 million in 2004 increased when compared to $73.5 million in 2003 due to retail sales growth and higher non-territorial energy sales. However, operating revenues and expenses recorded by the Company in 2003 were unusually high as compared to 2002. An increase of $62 million in other electric revenues resulted from the termination of the Company’s purchased power agreement with Dynegy, Inc. (Dynegy), the income effect of which was offset by a $60 million expense related to the establishment of a regulatory liability in connection with an accounting order issued by the Mississippi Public Service Commission (PSC). See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

RESULTS OF OPERATIONS

A condensed statement of income is as follows:

				Increase (Decrease)
	Amount			From Prior Year
	2005			2005			2004			2003
				(in thousands)
Operating revenues	$	969,733		$	59,407		$	40,402		$	45,759
Fuel		358,572			33,690			95,189			(52,700	)
Purchased power		143,492			36,729			13,566			41,864
Other operation and maintenance		239,622			2,144			(62,198	)		67,663
Depreciation and amortization		33,549			(5,841	)		(16,310	)		(1,938	)
Taxes other than income taxes		60,058			4,486			1,581			(1,527	)
Total operating expenses		835,293			71,208			31,828			53,362
Operating income		134,440			(11,801	)		8,574			(7,603	)
Total other income and (expense)		(12,525	)		2,417			1,898			7,525
Less —
Income taxes		46,374			(4,292	)		5,351			(564	)
Net income		75,541			(5,092	)		5,121			486
Dividends on preferred stock		1,733			(2,099	)		1,819			—
Net income after dividends on preferred stock	$	73,808		$	(2,993	)	$	3,302		$	486

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

Revenues

Details of the Company’s operating revenues in 2005 and the prior two years are as follows:

	Amount
	2005			2004			2003
	(in thousands)
Retail — prior year	$	584,313		$	516,301		$	536,827
Change in -
Sales growth and weather		(15,734	)		3,555			(367	)
Fuel cost recovery and other		50,281			64,457			(20,159	)
Retail — current year		618,860			584,313			516,301
Sales for resale —
Non-affiliates		283,413			265,863			249,986
Affiliates		50,460			44,371			26,723
Total sales for resale		333,873			310,234			276,709
Contract termination		—			—			62,111
Other electric operating revenues		17,000			15,779			14,803
Total electric operating revenues	$	969,733		$	910,326		$	869,924
Percent change		6.5	%		4.6	%		5.6	%

     Total retail revenues for 2005 increased 5.9 percent when compared to 2004 as a result of higher fuel revenue due to the increase in fuel cost. This increase in retail revenues was offset by reductions for the loss of customers in all major classes as a result of Hurricane Katrina. Total retail revenues for 2004 increased 13.2 percent when compared to 2003. While higher fuel costs accounted for 92 percent of this increase, sales growth, particularly in the industrial class, also contributed to the increase. Retail revenues for 2003 decreased approximately 3.8 percent when compared to 2002 as a result of decreased fuel revenues and, to a lesser extent, decreases in kilowatt-hour (KWH) energy sales due to milder than normal weather in the Company’s service area and the sluggish economy.

     Fuel revenues generally represent the direct recovery of fuel expenses including purchased power. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and have no effect on net income. The fuel cost recovery and other revenues increased in 2005 when compared to 2004 as a result of higher fuel costs. In 2004, fuel cost recovery and other revenues increased as compared to 2003 due to an increase in fuel expenses resulting from consistently higher fuel prices and a slight increase in retail rates that became effective in 2004. During 2003, the fuel cost recovery and other revenues decreased $20 million compared to 2002 due to lower generation and fewer fuel purchases as a result of milder than normal weather in 2003.

     Sales for resale to non-affiliates are influenced by the non-affiliate utilities’ own customer demand, plant availability, and fuel costs. In 2005, total revenues from sales for resale to non-affiliates increased $17.5 million or 6.6 percent as compared to 2004. This increase primarily resulted from an increase in price per KWH resulting from higher fuel costs. Total revenues from sales for resale to non-affiliates increased in 2004 by $14.4 million, or 5.7 percent. This increase primarily resulted from a $32.7 million increase in energy revenues, of which approximately $6 million was associated with increased KWH sales and $26.7 million was associated with higher fuel prices. Total revenues from sales for resale to non-affiliates increased in 2003 from 2002 as a result of increases in average sales price per KWH and increased KWH sales to wholesale non-affiliate customers. The increase in energy revenues was partially offset by an $18.3 million decrease in capacity revenues as a result of the termination of a contract with Dynegy in 2003.

     Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. As compared to the prior year, KWH sales to these utilities decreased 5.0 percent due to Hurricane Katrina in 2005, increased 3.3 percent in 2004, and remained relatively flat in 2003, with the related revenues increasing 16.2 percent, 12.4 percent, and 1.6 percent, respectively. The customer demand experienced by these utilities is determined by factors very similar to those experienced by the Company. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. KWH sales to non-territorial customers decreased 41 percent as compared to 2004 primarily due to Hurricane Katrina.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

     Energy sales to affiliated companies within the Southern Company electric system as well as purchases of energy vary from year to year depending on demand and the availability and cost of generating resources at each company. These sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC). These energy sales do not have a significant impact on earnings since the energy is generally sold at marginal cost.

Energy Sales

KWH sales for 2005 and percent change by year were as follows:

	KWH		Percent Change
	2005		2005			2004			2003
	(in millions)
Residential		2,180		(5.1	)%		1.9	%		(1.9	)%
Commercial		2,725		(8.2	)		1.9			0.4
Industrial		3,798		(10.3	)		3.0			(1.2	)
Other		38		(5.8	)		1.0			—
Total retail		8,741		(8.4	)		2.4			(0.9	)
Sales for resale
Non-affiliated		4,811		(20.2	)		2.6			9.2
Affiliated		897		(14.9	)		48.6			(55.3	)
Total		14,449		(13.1	)		4.5			(2.8	)

     Total retail KWH sales decreased in 2005 when compared to 2004 as the result of the loss of customers following Hurricane Katrina. Total retail KWH sales increased in 2004 when compared to 2003 as a result of economic recovery in the area which affected all customer classes, particularly the industrial class. Total retail KWH sales decreased in 2003 due to milder weather in 2003 when compared to 2002. Industrial sales also decreased in 2003 due to lower KWH sales and decreased fuel costs.

     The Company anticipates fairly strong growth over the next five years as the Company’s service area begins to recover from the effects of Hurricane Katrina. Retail sales are expected to grow at an annual rate of approximately 4.6 percent through 2010, as the rebuilding of residential homes and commercial businesses takes place. Various industrial expansions in oil and gas exploration, production, and refining are also expected to contribute to the growth.

Expenses

In 2005 and 2004, total operating expenses increased $71.2 million or 9.3 percent and $31.8 million or 4.3 percent, respectively, primarily as the result of increases in fuel and purchased power, administrative and general expenses, and taxes other than income. In 2003, operating expenses increased $53.4 million or 7.9 percent over the prior year. This increase was due primarily to $60 million in Plant Daniel capacity expense recorded in connection with an accounting order from the Mississippi PSC. See Note 3 to the financial statements under “Retail Regulatory Matters –Performance Evaluation Plan” for further information.

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

	2005		2004		2003
Total generation (millions of KWHs)		12,499		14,058		12,850
Sources of generation(percent) —
Coal		70		69		74
Gas		30		31		26
Average cost of fuel per net KWH generated(cents)		3.11		2.50		1.96
Average cost of purchased power per net KWH(cents)		5.44		3.28		2.51

     Fuel expense increased $33.7 million in 2005 as compared to 2004. Approximately $71 million in additional fuel expenses resulted from higher coal, gas, transportation prices, and emission allowances, which were partially offset by a $37 million decrease resulting from unit outages that reduced generation. Fuel expense for 2004 increased $95 million as compared to 2003. Approximately $25 million of the increase was associated with increased generation and approximately $70 million of the increase was due to higher coal and gas prices. Fuel expense for 2003 decreased $53 million due to decreased generation and lower average cost of fuel.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income since they are offset by fuel revenues under the Company’s fuel cost recovery clause. See Note 1 to the financial statements under “Fuel Costs” for additional information.

     Purchased power expense increased $37 million, or 34.4 percent, in 2005 when compared to 2004. The increase is primarily the result of the reduction in generation due to the damage caused by Hurricane Katrina. In 2004, purchased power expense increased $13.6 million, or 14.6 percent when compared to 2003. The increase was primarily due to an increase in purchases from non-affiliates to meet increased load and offset higher priced self-generation resulting from increased fuel costs. In 2003, purchased power expense increased $41.9 million when compared to 2002. The increase was primarily due to an increase in purchased power expense from affiliate companies. Those purchases were more economical than self generation due to the increased cost of natural gas in 2003. Energy purchases vary from year to year depending on demand and the availability and cost of the Company’s generating resources. These expenses do not have a significant impact on earnings since the energy purchases are generally offset by energy revenues through the Company’s fuel cost recovery clause.

     Other operations expense increased $7.9 million, or 4.9 percent, in 2005 as compared to 2004 primarily as a result a $5.2 million increase in employee benefit expenses, a $1.7 million increase in rent expense on the Plant Daniel combined cycle lease, and higher bad debt expense of $1 million primarily resulting from Hurricane Katrina. In 2004, other operations expense decreased $69.2 million, or 30 percent, and increased $71.2 million, or 45.0 percent, in 2003 due to approximately $11 million incurred in 2003 to restructure the Plant Daniel combined cycle lease agreement and $60 million in expense recorded in 2003 in connection with the recognition of a regulatory liability following an accounting order from the Mississippi PSC related to Plant Daniel capacity expense. See FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” and Notes 3 and 7 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” and “Operating Leases – Plant Daniel Combined Cycle Generating Units,” respectively, for additional information.

     Maintenance expense decreased $5.7 million, or 7.5 percent, in 2005 as a result of a $1.1 million decrease in long-term service agreement expense associated with the Plant Daniel combined cycle units as a result of fewer fired operating hours in 2005 when compared to 2004 and a $4.5 million decrease in maintenance expense associated with changes in scheduled maintenance as a result of restoration efforts. These restoration expenses have been deferred in accordance with a Mississippi PSC order. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Cost Recovery” for additional information. Maintenance expense increased $7.0 million, or 9.9 percent, in 2004 primarily resulting from higher operating hours at Plant Daniel and increased distribution line maintenance during 2004 as compared to 2003. In 2003, maintenance expense decreased $3.6 million, or 4.9 percent over the prior year, primarily due to a decrease of approximately 50 percent in operating hours at Plant Daniel Units 3 and 4. See Note 7 to the financial statements under “Long-Term Service Agreements” for further information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

     Depreciation and amortization expense decreased $5.8 million in 2005 and $16.3 million in 2004 as compared to the prior years primarily as a result of amortization related to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on the Plant Daniel Capacity. See Note 3 under “Retail Regulatory Matters – Performance Evaluation Plan” for additional information. In 2003, depreciation and amortization expense decreased $1.9 million due to the amortization related to the Company’s Environmental Compliance Overview Plan (ECO Plan) approved by the Mississippi PSC. The Company filed a depreciation study in 2005 with the Mississippi PSC and is awaiting approval. Depreciation expense would increase approximately $2.2 million annually effective January 1, 2006 if the depreciation study is approved as filed. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Compliance Overview Plan” for further information.

     In 2005, taxes other than income taxes increased 8.1 percent over the prior year due to a $2.9 million increase in ad valorem taxes and a $1.1 million increase in municipal franchise taxes. The retail portion, or approximately 82 percent, of the increase in ad valorem taxes is recoverable under the Company’s ad valorem tax cost recovery clause and, therefore, does not affect net income. The increase in municipal franchise taxes is directly related to the increase in total retail revenues. Taxes other than income taxes increased 2.9 percent in 2004 as compared to 2003 primarily due to additional municipal franchise taxes. Taxes other than income taxes decreased 2.8 percent in 2003 due to lower property taxes in 2003 as compared to 2002. The decrease in total other income and expense is due to interest on long-term debt decreasing in all years presented as a result of lower interest rates on debt outstanding and lower principal amount of debt outstanding.

Effects of Inflation

The Company is subject to rate regulation that is based on the recovery of costs. PEP is based on annual projected costs, including estimates for inflation. When inflation exceeds the projected costs used in rate regulation, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. The inflation rate has been relatively low in recent years and any adverse effect of inflation on the Company has not been significant.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in southeast Mississippi and wholesale customers in the southeastern United States. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “FERC Matters” and “Retail Regulatory Matters” for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors. These factors include the ability of the Company to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area in the aftermath of Hurricane Katrina.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging violations of the New Source Review (NSR)

II-242

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric, including three co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in its notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not refiled. See Note 3 to the financial statements under “Environmental Matters – New Source Review Actions.”

     The Company believes that it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The Mississippi Department of Environmental Quality (MDEQ) formally adopted the 2002 NSR rules effective July 28, 2005, but did not adopt the provisions vacated by the District of Columbia Circuit. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the State of Mississippi’s implementation of such rules, as well as the outcome of any additional legal challenges, and therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

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Environmental Statutes and Regulations

General

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act.

     Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through the Company’s ECO Plan. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Compliance Overview Plan” for additional information. Through 2005, the Company had invested approximately $46.8 million in capital projects to comply with these requirements, with annual totals of $4.0 million, $2.9 million, and $10.4 million for 2005, 2004, and 2003, respectively. Over the next decade the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $466 million, including $6.4 million, $27.0 million, and $40.1 million for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $7.7 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. During, 2005, the EPA’s fine particulate matter nonattainment designations also became effective for several areas across the United States. No areas within the Company’s service area, however, have been designated as nonattainment under either the eight-hour ozone standard or the fine particulate matter standard.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including the State of Mississippi are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and

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NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x,and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

Environmental Remediation

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in the financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. The Company has received authority from the Mississippi PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Mississippi PSC, these rates are adjusted annually. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Compliance Overview Plan” for additional information.

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010-2012. The Company is continuing to evaluate future energy and emission profiles relative to

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the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005, are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $5.7 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005, is not expected to exceed $7.4 million, of which $4.4 million relates to sales inside the service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, Southern Power, and Southern Company Services, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

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     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot be determined at this time.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company cannot be determined at this time.

Transmission

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

PSC Matters

Performance Evaluation Plan (PEP)

See Note 3 to the financial statements under “Retail Regulatory Matters – Performance Evaluation Plan” for information on the Company’s base rates. In May 2004, the Mississippi PSC approved the Company’s request to reclassify 266 megawatts of Plant Daniel Units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004, and authorized the Company to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. The Company is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 order, as approved in the May 2004 order, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in reductions of costs in each of those years.

     On December 1, 2005, the Company submitted its annual PEP filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, the Company has requested that the Mississippi PSC approve a temporary change to allow it to exceed this cap as a result of the ongoing effects of Hurricane Katrina. The Company has requested a 5 percent increase in total retail revenues or $32 million increase in retail base revenues to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.

Fuel Cost Recovery

The Company establishes annually a fuel cost recovery factor that is approved by the Mississippi PSC. Over the past year, the Company has continued to experience higher than expected fuel costs for coal and natural gas. The Company is required to file for an adjustment to the fuel cost recovery factor annually; such filing occurred in November 2005. As a result, the Mississippi PSC approved an increase in the fuel cost recovery factor effective January 2006 in an amount equal to 12 percent of total retail revenues. The Company’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on the Company’s revenues or net income.

Storm Damage Cost Recovery

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

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property. The Company’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.

     Hurricane Katrina hit the coast of Florida, Alabama, Mississippi, and Louisiana on August 29, 2005, causing substantial damage. The Company sustained significant damage to its distribution and transmission facilities. The Company’s Plant Watson was also damaged. Plant Watson has six generating units, including three gas-fired units totaling 262 megawatts (MW), two coal-fired units totaling 750 MW, and a 40 MW gas turbine. Both of the coal-fired units at the plant have been returned to service. The gas units operate primarily to serve summer peak loads. Repairs to the gas units are expected to be completed by June 1, 2006.

     As of December 31, 2005, approximately 19,200 of the Company’s customers remained unable to receive service. Prior to Hurricane Katrina, the Company had a balance of approximately $3 million in its property reserve. The Company currently estimates the total incremental cost of repairing the damages to its facilities and restoring service to customers will be approximately $277 million net of approximately $68 million of insurance proceeds. Business and government authorities are still reviewing redevelopment plans for portions of the severely damaged areas along the Mississippi shoreline. The ultimate impact of the redevelopment plans in these areas on the Company’s cost estimates cannot now be determined.

     The Mississippi PSC issued an Interim Accounting Order on October 21, 2005, requiring the Company to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. Total Hurricane Katrina costs incurred through December 31, 2005, include approximately $132.6 million of operations and maintenance expenditures and approximately $148.8 million of capital-related expenditures. On December 7, 2005, the Company filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. The Company is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to proposed state legislation to allow securitized financing and federal grant assistance. See Notes 1 and 3 to the financial statements under “Provision for Property Damage” and “Retail Regulatory Matters – Storm Damage Cost Recovery,” respectively, for additional information.

Other Matters

In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pre-tax pension (income)/expense, before tax, of approximately $2.7 million, $0.6 million, and ($1.7) million, in 2005, 2004 and 2003 respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. Postretirement benefit costs for the Company were $5.3 million, $4.5 million, and $4.0 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefits are components of regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

     The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for information regarding these matters.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors.

Electric Utility Regulation

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

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

Contingent Obligations

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

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

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

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

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

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

Unbilled Revenues

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

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Plant Daniel Operating Lease

As discussed in Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units,” the Company leases a 1,064 megawatt natural gas combined cycle facility at Plant Daniel (Facility) from Juniper Capital L.P. (Juniper). For both accounting and rate recovery purposes, this transaction is treated as an operating lease, which means that the related obligations under this agreement are not reflected in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” herein for further information. The operating lease determination was based on assumptions and estimates related to the following:

• Fair market value of the Facility at lease inception.

• The Company’s incremental borrowing rate.

• Timing of debt payments and the related amortization of the initial acquisition cost during the initial lease term.

• Residual value of the Facility at the end of the lease term.

• Estimated economic life of the Facility.

• Juniper’s status as a voting interest entity.

     The determination of operating lease treatment was made at the inception of the lease agreement and is not subject to change unless subsequent changes are made to the agreement. However the Company also is required to monitor Juniper’s ongoing status as a voting interest entity. Changes in that status could require the Company to consolidate the Facility’s assets and the related debt and to record interest and depreciation expense of approximately $37 million annually, rather than annual lease expense of approximately $27 million.

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on the Company’s financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. At December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $9.5 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”

Stock Options

On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2005. Net cash flow from operating activities totaled $42 million, $119 million, and $186 million for 2005, 2004, and 2003, respectively. The $77 million decrease for 2005 was primarily due to the storm damage costs related to Hurricane Katrina. These costs are expected to be recovered from customers in future periods and are included in the balance sheet under

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Deferred Property Damage. See FUTURE EARNINGS POTENTIAL “PSC Matters – Storm Damage Cost Recovery” for additional information.

     Significant changes in the balance sheet as of December 31, 2005 as compared to 2004 primarily relate to Hurricane Katrina storm restoration activities. These storm-related changes include increases in other accounts and notes receivable of $14.7 million, insurance receivable of $60 million, accumulated provision for uncollectible accounts of $1.5 million, prepaid income taxes of $32 million, notes payable of $202 million, affiliated accounts payable of $73.5 million, and accumulated deferred income taxes of $68.9 million. Current liabilities exceed current assets primarily due to the notes payable related to storm restoration activities. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Storm Damage Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Storm Damage Recovery” for additional information related to the deferral of the restoration costs, including both capital and operation and maintenance expenditures.

     The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, increased from 63.7 percent in 2004 to 64.3 percent at December 31, 2005. The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company plans to obtain the funds required for construction, continued storm damage restoration, and other purposes from sources similar to those used in the past. In addition, the Company is considering other financing options, such as securitization, for storm recovery costs. The amount, type, and timing of any future financings, if needed, will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors.

     The issuance of securities by the Company is subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933 (1933 Act). The amounts registered under the 1933 Act and the amounts authorized by the FERC, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

     To meet short-term cash needs and contingencies, the Company has various sources of liquidity. At the beginning of 2006, the Company had approximately $14.3 million of cash and cash equivalents and $276 million of unused credit arrangements with banks. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2005, the Company had $152 million outstanding in commercial paper notes.

     On February 24, 2006, the Company borrowed $100 million under a promissory note to Barclays Bank PLC due August 24, 2006. The borrowing bears interest at a variable rate based on LIBOR plus 0.3 percent, is unsecured, and may be prepaid at any time upon three days’ prior written notice. The promissory note includes representations and warranties, covenants, and events of default, including a maximum debt to total capitalization ratio of 65 percent. The promissory note also includes limitations on liens, consolidations, mergers, and sale of all or substantially all of the Company’s assets. The borrowing may become due and payable upon an event of default and expiration of any applicable cure periods. Events of default include: (i) nonpayment of obligations under the promissory note, (ii) failure to perform any covenant or agreement in the promissory note, (iii) material misrepresentations, (iv) failure to pay, or

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

certain other defaults under, certain other indebtedness, and (v) certain bankruptcy or insolvency events.

Financing Activities

During 2005, the Company continued a program to retire higher-cost securities and replace them with lower-cost capital. See the statements of cash flows for further details.

     In June 2005, the Company issued $30 million of senior notes. The proceeds from this sale were used to redeem $30 million principal amount of first mortgage bonds due December 1, 2025. The related first mortgage bond indenture was legally defeased in June 2005 and retired in December 2005. As a result of this transaction, there are no longer any first mortgage bond liens on the Company’s property.

     In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Off-Balance Sheet Financing Arrangements

In June 2003, the Company entered into a restructured lease agreement for the Facility with Juniper, as discussed in Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units.” Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50 percent of Juniper’s assets. The Company does not consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. Accordingly, the lease is not reflected in the balance sheets.

     The initial lease term ends in 2011, and the lease includes a purchase and renewal option based on the cost of the Facility at the inception of the lease, which was approximately $370 million. The Company is required to amortize approximately four percent of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, the Company may elect to renew for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17 percent of the initial completion cost over the renewal period. Upon termination of the lease, at the Company’s option, it may either exercise its purchase option or the Facility can be sold to a third party.

     The lease also provides for a residual value guarantee, approximately 73 percent of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, the Company’s exposure related to these agreements was not material.

Market Price Risk

Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation and sensitivity analysis.

     The Company’s market risk exposures relative to interest rate changes have changed compared with the December 31, 2004, reporting period as a result of storm damage from Hurricane Katrina. The Company will manage this increased exposure through a number of means, including interest rate hedges, where appropriate.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

     The Company does not currently hedge interest rate risk. The weighted average interest rate on variable long-term debt at January 1, 2006, was 3.96 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $1.2 million at December 31, 2005. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

     To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. At December 31, 2005, exposure from these activities was not material to the Company’s financial statements.

     In addition, at the instruction of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2005, exposure from these activities was not material to the Company’s financial statements.

     The change in fair value of energy contracts and year-end valuations are as follows:

	Change in Fair Value
	2005			2004
	(in thousands)
Contracts beginning of year	$	889		$	2,470
Contracts realized or settled		(13,816	)		(9,181	)
Current period changes (a)		40,033			7,600
Contracts end of year	$	27,106		$	889

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

Source of Year-End Valuation Prices
	Total			Maturity
	Fair Value			Year 1			2-3 Years
	(in thousands)
Actively quoted	$	27,645		$	19,998		$	7,647
External sources		(539	)		(539	)		—
Models and other methods		—			—			—
Contracts end of year	$	27,106		$	19,459		$	7,647

     These contracts are related primarily to fuel hedging programs under which unrealized gains and losses from mark to market adjustments are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the Company’s energy cost management clause.

     Gains and losses on forward contracts for the sale of electricity that do not represent hedges are recognized in the statements of income as incurred. For the years ended December 31, 2005, 2004, and 2003, these amounts were not material.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	27,463
Other comprehensive income		(342	)
Net income		(15	)
Total fair value	$	27,106

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

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $126 million for 2006, of which $30 million is related to Hurricane Katrina restoration, $112 million for 2007, and $139 million for 2008. Environmental expenditures included in these amounts are $6.4 million, $27.0 million, and $40.4 million for 2006, 2007, and 2008, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental

II-253

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

regulations; FERC rules and transmission regulations; load projections; storm impacts; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

Contractual Obligations

			2007-		2009-		After
	2006		2008		2010		2010		Total
					(in thousands)
Long-term debt and preferred securities(a) —
Principal	$	100,000	$	—	$	40,000	$	238,777	$	378,777
Interest		14,137		28,274		26,418		287,922		356,751
Commodity derivative obligations(b)		969		105		—		—		1,074
Preferred stock dividends(c)		1,728		3,456		3,456		—		8,640
Operating leases		33,927		65,371		61,908		32,513		193,719
Purchase commitments(d)
Capital(e)		126,000		251,000		—		—		377,000
Coal		184,342		82,690		—		—		267,032
Natural gas(f)		168,311		137,809		11,876		42,269		360,265
Long-term service agreements		13,198		22,796		23,219		95,538		154,751
Post retirement benefit trust(g)		260		520		—		—		780
Total	$	642,872	$	592,021	$	166,877	$	697,019	$	2,098,789

(a)	All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization.
(b)	For additional information, see Notes 1 and 6 to the financial statements herein.
(c)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(d)	The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $240 million, $237 million, and $300 million, respectively.
(e)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)	Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)	The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, retail sales growth, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters, and EPA civil actions;

• the effects, extent and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

II-256

STATEMENTS OF INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Revenues:
Retail sales	$	618,860		$	584,313		$	516,301
Sales for resale —
Non-affiliates		283,413			265,863			249,986
Affiliates		50,460			44,371			26,723
Contract termination		—			—			62,111
Other revenues		17,000			15,779			14,803
Total operating revenues		969,733			910,326			869,924
Operating Expenses:
Fuel		358,572			324,882			229,693
Purchased power —
Non-affiliates		32,208			33,528			18,523
Affiliates		111,284			73,235			74,674
Other operations —
Plant Daniel capacity		—			—			60,300
Other		168,355			160,477			169,333
Maintenance		71,267			77,001			70,043
Depreciation and amortization		33,549			39,390			55,700
Taxes other than income taxes		60,058			55,572			53,991
Total operating expenses		835,293			764,085			732,257
Operating Income		134,440			146,241			137,667
Other Income and (Expense):
Interest income		1,718			777			617
Interest expense		(11,230	)		(11,776	)		(14,369	)
Interest expense to affiliate trust		(2,598	)		(1,948	)		—
Distributions on mandatorily redeemable preferred securities		—			(630	)		(2,520	)
Other income (expense), net		(415	)		(1,365	)		(568	)
Total other income and (expense)		(12,525	)		(14,942	)		(16,840	)
Earnings Before Income Taxes		121,915			131,299			120,827
Income taxes		46,374			50,666			45,315
Net Income		75,541			80,633			75,512
Dividends on Preferred Stock		1,733			3,832			2,013
Net Income After Dividends on Preferred Stock	$	73,808		$	76,801		$	73,499

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

II-257

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Activities:
Net income	$	75,541		$	80,633		$	75,512
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		63,319			60,260			60,226
Deferred income taxes and investment tax credits, net		118,316			44,424			(8,562	)
Plant Daniel capacity		(25,125	)		(16,508	)		60,300
Pension, postretirement, and other employee benefits		2,938			(1,084	)		(1,014	)
Tax benefit of stock options		3,723			1,532			3,018
Other, net		1,493			(1,823	)		1,816
Changes in certain current assets and liabilities —
Receivables		(107,836	)		(26,250	)		20,864
Fossil fuel stock		(25,745	)		5,528			2,070
Materials and supplies		(6,234	)		(3,768	)		(1,607	)
Prepaid income taxes		(40,059	)		3,419			(5,638	)
Other current assets		(2,498	)		(2,018	)		6,807
Hurricane Katrina accounts payable		(82,102	)		—			—
Other accounts payable		40,255			(5,555	)		(20,602	)
Accrued taxes		4,001			151			(8,976	)
Accrued compensation		674			82			(2,568	)
Over recovered regulatory clause revenues		20,831			(25,761	)		694
Other current liabilities		441			6,052			3,264
Net cash provided from operating activities		41,933			119,314			185,604
Investing Activities:
Property additions		(158,084	)		(72,066	)		(72,134	)
Cost of removal net of salvage		(26,140	)		(3,189	)		(5,811	)
Construction payables		16,417			1,243			(1,414	)
Other		(2,655	)		(2,066	)		—
Net cash used for investing activities		(170,462	)		(76,078	)		(79,359	)
Financing Activities:
Increase in notes payable, net		202,124			—			—
Proceeds —
Senior notes		30,000			40,000			90,000
Preferred stock		—			30,000			—
Capital contributions from parent company		(25	)		1,791			4,912
Redemptions —
First mortgage bonds		(30,000	)		—			(33,350	)
Pollution control bonds		—			—			(850	)
Senior notes		—			(80,000	)		(86,628	)
Preferred stock		—			(28,388	)		—
Payment of preferred stock dividends		(1,733	)		(1,829	)		(2,013	)
Payment of common stock dividends		(62,000	)		(66,200	)		(66,000	)
Other		(2,481	)		(785	)		(5,891	)
Net cash provided from (used for) financing activities		135,885			(105,411	)		(99,820	)
Net Change in Cash and Cash Equivalents		7,356			(62,175	)		6,425
Cash and Cash Equivalents at Beginning of Year		6,945			69,120			62,695
Cash and Cash Equivalents at End of Year	$	14,301		$	6,945		$	69,120
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest	$	13,499		$	12,084		$	17,334
Income taxes (net of refunds)		(40,801	)		6,654			60,618

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

II-258

BALANCE SHEETS
At December 31, 2005 and 2004
Mississippi Power Company 2005 Annual Report

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

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

II-259

BALANCE SHEETS
At December 31, 2005 and 2004
Mississippi Power Company 2005 Annual Report

	2005		2004
	(in thousands)
Liabilities and Stockholder’s Equity
Current Liabilities:
Notes payable	$	202,124	$	—
Accounts payable —
Affiliated		122,899		19,568
Other		89,598		52,688
Customer deposits		7,298		9,053
Accrued taxes —
Income taxes		17,736		396
Other		48,296		44,285
Accrued interest		3,408		1,731
Accrued compensation		24,587		23,913
Regulatory clauses over recovery		26,188		5,356
Plant Daniel capacity		13,008		25,125
Other		40,334		27,067
Total current liabilities		595,476		209,182
Long-term Debt(See accompanying statements)		242,548		242,498
Long-term Debt Payable to Affiliated Trust(See accompanying statements)		36,082		36,082
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		266,629		167,345
Deferred credits related to income taxes		19,003		20,261
Accumulated deferred investment tax credits		17,465		18,654
Employee benefit obligations		58,318		57,275
Other cost of removal obligations		81,284		76,228
Other regulatory liabilities		13,411		23,154
Other		57,113		49,817
Total deferred credits and other liabilities		513,223		412,734
Total Liabilities		1,387,329		900,496
Preferred Stock(See accompanying statements)		32,780		32,780
Common Stockholder’s Equity(See accompanying statements)		561,160		545,837
Total Liabilities and Stockholder’s Equity	$	1,981,269	$	1,479,113
Commitments and Contingent Matters(See notes)

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

II-260

STATEMENTS OF CAPITALIZATION
At December 31, 2005 and 2004
Mississippi Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long-Term Debt:
First mortgage bonds — 6.875% due 2025	$	—		$	30,000
Long-term notes payable —
5.4% to 5.625% due 2033-2035		120,000			90,000
Adjustable rates (4.64% at 1/1/06) due 2009		40,000			40,000
Total long-term notes payable		160,000			130,000
Other long-term debt —
Pollution control revenue bonds — non-collateralized:
Variable rates (3.45% to 3.87% at 1/1/06) due 2020-2028		82,695			82,695
Unamortized debt premium (discount), net		(147	)		(197	)
Total long-term debt (annual interest requirement — $11.5 million)		242,548			242,498			27.8	%		28.3	%
Long-term Debt Payable to Affiliated Trust:
7.20% due 2041 (annual interest requirement — $2.6 million)		36,082			36,082			4.1			4.2
Cumulative Preferred Stock:
$100 par value
Authorized — 1,244,139 shares
Outstanding — 334,210 shares
4.40% to 5.25% (annual dividend requirement — $1.7 million)		32,780			32,780			3.8			3.8
Common Stockholder’s Equity:
Common stock, without par value —
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares		37,691			37,691
Paid-in capital		299,536			295,837
Retained earnings		227,701			215,893
Accumulated other comprehensive income (loss)		(3,768	)		(3,584	)
Total common stockholder’s equity		561,160			545,837			64.3			63.7
Total Capitalization	$	872,570		$	857,197			100.0	%		100.0	%

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

II-261

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
	(in thousands)
Balance at December 31, 2002	$	37,691	$	285,606		$	195,920		$	(1,264	)	$	517,953
Net income after dividends on preferred stock		—		—			73,499			—			73,499
Capital contributions from parent company		—		7,235			—			—			7,235
Other comprehensive income (loss)		—		—			—			(198	)		(198	)
Cash dividends on common stock		—		—			(66,000	)		—			(66,000	)
Balance at December 31, 2003		37,691		292,841			203,419			(1,462	)		532,489
Net income after dividends on preferred stock		—		—			76,801			—			76,801
Capital contributions from parent company		—		3,323			—			—			3,323
Other comprehensive income (loss)		—		—			—			(2,122	)		(2,122	)
Cash dividends on common stock		—		—			(66,200	)		—			(66,200	)
Other		—		(327	)		1,873			—			1,546
Balance at December 31, 2004		37,691		295,837			215,893			(3,584	)		545,837
Net income after dividends on preferred stock		—		—			73,808			—			73,808
Capital contributions from parent company		—		3,699			—			—			3,699
Other comprehensive income (loss)		—		—			—			(184	)		(184	)
Cash dividends on common stock		—		—			(62,000	)		—			(62,000	)
Balance at December 31, 2005	$	37,691	$	299,536		$	227,701		$	(3,768	)	$	561,160

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

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Mississippi Power Company 2005 Annual Report

	2005			2004			2003
Net income after dividends on preferred stock	$	73,808		$	76,801		$	73,499
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(167), $(1,131) and $(123), respectively		(269	)		(1,825	)		(198	)
Change in fair value of marketable securities, net of tax of $49		—			80			—
Changes in fair value of qualifying hedges, net of tax of $53 and $(184), respectively		85			(297	)		—
Less: Reclassification adjustment for amounts included in net income, net of tax of $(49)		—			(80	)		—
Total other comprehensive income (loss)		(184	)		(2,122	)		(198	)
Comprehensive Income	$	73,624		$	74,679		$	73,301

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

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Mississippi Power Company 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Mississippi Power Company (Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies, Alabama Power, Georgia Power, Gulf Power, the Company, and Savannah Electric, provide electric service in four southeastern states. The Company operates as a vertically integrated utility providing service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power, related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power, are regulated by the Federal Energy Regulatory Commission (FERC). SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

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

      Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of PUHCA. The Company is also subject to regulation by the FERC and the Mississippi Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $51.6 million, $45.3 million, and $46.1 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA, and management believes they are reasonable.

      The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced in the last two years, assistance for storm restoration has caused an increase in these activities. The total amount of storm restoration provided to Alabama Power, Georgia Power, and Gulf Power in 2004 and 2005 was $3.3 million and $1.0 million, respectively. These activities were billed at cost. The Company received storm restoration assistance from other Southern Company subsidiaries in 2005 totaling $73.5 million.

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Mississippi Power Company 2005 Annual Report

     The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of all associated expenditures and costs. The Company reimbursed Alabama Power for the Company’s proportionate share of related expenses which totaled $8.2 million, $7.2 million, and $6.6 million in 2005, 2004, and 2003, respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs. Gulf Power reimbursed the Company for Gulf Power’s proportionate share of related expenses which totaled $18.4 million, $17.8 million, and $17.7 million in 2005, 2004, and 2003, respectively. See Notes 4 and 5 for additional information on certain deferred tax liabilities payable to affiliates.

     The retail operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” for additional information.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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

	2005				2004				Note
	(in thousands)
Hurricane Katrina		$	209,324			$	—		(i)
Property Damage			(500	)			(5,035	)	(g)
Deferred income tax charges			10,443				11,358		(a)
Property tax			15,148				11,199		(b)
Vacation pay			6,954				6,125		(c)
Loss on reacquired debt			10,381				9,437		(d)
Loss on redeemed preferred stock			914				1,086		(e)
Other regulatory assets			405				460
Fuel-hedging assets			232				2,666		(f)
Asset retirement obligations			10,668				1,398		(a)
Deferred income tax credits			(20,559	)			(21,789	)	(a)
Other cost of removal obligations			(81,284	)			(76,228	)	(a)
Plant Daniel capacity			(18,667	)			(43,792	)	(h)
Fuel-hedging liabilities			(27,695	)			(4,027	)	(f)
Other liabilities			(660	)			(142	)	(g)
Total		$	115,104			$	(107,284	)

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year.
(c)	Recorded as earned by employees and recovered as paid, generally within one year.
(d)	Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
(e)	Amortized over a period beginning in 2004 that is not to exceed seven years.
(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).
(g)	Recorded and recovered as approved by the Mississippi PSC.
(h)	Amortized over a four-year period ending in 2007.
(i)	For additional information, see Note 3 under “Retail Regulatory Matters — Storm Damage Cost Recovery.”

     In the event that a portion of the Company’s operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are

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Mississippi Power Company 2005 Annual Report

not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are to be reflected in rates. See Note 3 herein under “Retail Regulatory Matters — Storm Damage Cost Recovery.”

Revenues

Energy and other revenues are recognized as services are rendered. Capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues are accrued at the end of each fiscal period. The Company’s retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery factor annually.

     The Company has a diversified base of customers. For years ended December 31, 2005 and December 31, 2004, no single customer or industry accounted for 10 percent or more of revenue. However, for the year ended December 31, 2003, Dynegy, Inc. (Dynegy) accounted for approximately 14.8 percent of revenues as a result of non-recurring contract termination revenues. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel costs also included gains and/or losses from fuel hedging programs as approved by the Mississippi PSC.

Income Taxes

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

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of funds used during construction for projects over $10 million.

     The Company’s property, plant, and equipment consisted of the following at December 31 (in thousands):

	2005		2004
Generation	$	833,598	$	824,755
Transmission		390,961		377,717
Distribution		624,769		547,231
General		137,966		132,839
Total plant in service	$	1,987,294	$	1,882,542

     The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense except for the cost of maintenance of coal cars and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company’s fuel clause.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4 percent in each of 2005, 2004, and 2003. Depreciation studies are conducted periodically to update the composite rates. The Company filed a study in 2005 with the Mississippi PSC and is awaiting approval. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost, together with the cost of removal, less salvage, is charged to the accumulated

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Mississippi Power Company 2005 Annual Report

depreciation provision. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of facilities.

     In January 2006, the Mississippi PSC issued an accounting order directing the Company to exclude from its calculation of depreciation expense approximately $1.2 million related to capitalized Hurricane Katrina costs since these costs will be recovered separately.

     In December 2003, the Mississippi PSC issued an interim accounting order directing the Company to expense and record a regulatory liability of $60.3 million while it considered the Company’s request to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional cost of service. In May 2004, the Mississippi PSC approved the Company’s request effective January 1, 2004 and ordered the Company to amortize the regulatory liability previously established to reduce depreciation and amortization expenses as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted FASB Statement No.143, Accounting for Asset Retirement Obligations, which established new accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived assets. The present value of the ultimate cost for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because of the timing of their requirements was dependent on future events. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or Interpretation No. 47.

     The Company has retirement obligations related to various landfill sites and underground storage tanks. In connection with the adoption of Interpretation No. 47, the Company also recorded additional asset retirement obligations (and assets) of $9.5 million, primarily related to asbestos. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.

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

	2005		2004
	(in millions)
Balance, beginning of year	$	5.5	$	2.5
Liabilities incurred		9.5		—
Liabilities settled		—		—
Accretion		0.4		0.2
Cash flow revisions		—		2.8
Balance, end of year	$	15.4	$	5.5

     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $14.1 million.

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Mississippi Power Company 2005 Annual Report

Impairment of Long-Lived Assets and Intangibles

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

Provision for Property Damage

The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to a regulatory liability account. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. The annual accruals may range from $1.5 million to $4.6 million with a maximum reserve totaling $23 million. The Company accrued $1.5 million in 2005, $4.6 million in 2004, and $2.5 million in 2003. See Note 3 under “Storm Damage Cost Recovery” for additional information regarding the depletion of these reserves following Hurricane Katrina and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which may be approved by the Mississippi PSC to replenish these reserves.

Environmental Cost Recovery

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through retail rates. The Company filed its 2006 ECO Plan in February 2006, which if approved as filed, is anticipated to result in a slight decrease in customer prices.

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.

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Mississippi Power Company 2005 Annual Report

     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on net income is as follows:

	As		Option			Pro
	Reported		Impact			Forma
	(in thousands)
2005	$	73,808	$	(648	)	$	73,160
2004		76,801		(682	)		76,119
2003		73,499		(758	)		72,741

     The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:

	2005			2004			2003
Interest rate		3.9	%		3.1	%		2.7	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.9	%		19.6	%		23.6	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

Financial Instruments

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

     The Mississippi PSC has approved the Company’s request to implement an ECM which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company’s jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.

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

     Other financial instruments for which the carrying amount did not equal the fair value at December 31 were as follows:

	Carrying		Fair
	Amount		Value
	(in thousands)
Long-term debt:
2005	$	278,630	$	273,278
2004	$	278,580	$	282,884

     The fair values were based on either closing market price or closing price of comparable instruments.

Comprehensive Income

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

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Mississippi Power Company 2005 Annual Report

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. The Company has established a wholly-owned trust established to issue preferred securities. However, the Company is not the primary beneficiary of the trust. Therefore, the investments in this trust are reflected as Other Investments and the related loan from the trust are reflected as Long-term Debt Payable to Affiliated Trust in the balance sheets. See Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for additional information.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are funded on a cash basis. The Company provides certain medical care and life insurance benefits for retired employees. In addition, trusts are funded to the extent required by the Mississippi PSC and the FERC. For the year ending December 31, 2006, postretirement trust contributions are expected to total approximately $260,000.

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

Pension Plans

The total accumulated benefit obligation for the pension plans was $235 million and $211 million for 2005 and 2004, respectively. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

	Projected
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	232,658		$	207,689
Service cost		6,566			6,153
Interest cost		13,089			12,249
Benefits paid		(10,703	)		(10,564	)
Actuarial loss and employee transfers		12,080			16,342
Amendments		1,347			789
Balance at end of year	$	255,037		$	232,658

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	222,543		$	210,285
Actual return on plan assets		33,654			20,419
Benefits paid		(9,497	)		(8,985	)
Employee transfers		(429	)		824
Balance at end of year	$	246,271		$	222,543

     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $234.3 million and $20.8 million, respectively. All plan assets are related to the qualified plan.

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Mississippi Power Company 2005 Annual Report

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

				Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	2005			2004
	(in thousands)
Funded status	$	(8,767	)	$	(10,115	)
Unrecognized transition obligation		(545	)		(1,090	)
Unrecognized prior service cost		14,288			14,423
Unrecognized net gain (loss)		3,915			8,315
Prepaid pension asset, net	$	8,891		$	11,533

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

	2005			2004
	(in thousands)
Prepaid pension asset	$	17,264		$	19,158
Employee benefit obligations		(16,357	)		(15,394	)
Other property and investment- other		2,224			2,445
Accumulated other comprehensive income		5,760			5,324
Prepaid pension, net	$	8,891		$	11,533

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

	2005			2004			2003
	(in thousands)
Service cost	$	6,566		$	6,153		$	5,607
Interest cost		13,089			12,249			11,965
Expected return on plan assets		(18,437	)		(18,325	)		(18,329	)
Recognized net (gain) loss		526			865			(1,847	)
Net amortization		937			(361	)		862
Net pension (income) expense	$	2,681		$	581		$	(1,742	)

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	2005
	(in thousands)
2006	$	11,112
2007		11,138
2008		11,288
2009		11,648
2010		11,987
2011 to 2015	$	70,609

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Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

	Accumulated
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	75,435		$	72,186
Service cost		1,427			1,330
Interest cost		4,242			4,015
Benefits paid		(3,937	)		(3,364	)
Actuarial (gain) loss		9,315			1,268
Balance at end of year	$	86,482		$	75,435

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	20,183		$	18,185
Actual return on plan assets		2,462			1,868
Employer contributions		4,051			3,494
Benefits paid		(3,937	)		(3,364	)
Balance at end of year	$	22,759		$	20,183

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

				Plan Assets
	Target			2005			2004
Domestic equity		28	%		31	%		27	%
International equity		18			18			15
Fixed income		35			36			45
Real estate		11			10			8
Private equity		8			5			5
Total		100	%		100	%		100	%

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

	Accrued Costs
	2005			2004
	(in thousands)
Funded status	$	(63,723	)	$	(55,253	)
Unrecognized transition obligation		2,543			2,889
Unrecognized prior service cost		1,398			1,504
Unrecognized net gain		26,919			19,211
Fourth quarter contributions		902			779
Accrued liability recognized in the Balance Sheets	$	(31,961	)	$	(30,870	)

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

	Net Periodic Costs
	2005			2004			2003
	(in thousands)
Service cost	$	1,427		$	1,330		$	1,149
Interest cost		4,242			4,015			3,898
Expected return on Plan assets		(1,563	)		(1,716	)		(1,598	)
Transition obligation		346			346			346
Prior service cost		106			106			106
Recognized net loss		706			408			116
Net postretirement cost	$	5,264		$	4,489		$	4,017

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $0.5 million and $1.2 million, respectively, and is expected to have a similar impact on future expenses.

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

	Benefit		Subsidy
	Payments		Receipts			Total
	(in thousands)
2006	$	4,092	$	(418	)	$	3,674
2007		4,433		(508	)		3,925
2008		4,779		(576	)		4,203
2009		5,186		(627	)		4,559
2010		5,521		(687	)		4,834
2011 to 2015	$	31,273		$(4,775	)	$	26,498

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefits plans were as follows:

	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00			3.50			3.75
Long-term return on plan assets		8.50			8.50			8.50

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of one percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows :

	1 Percent
	Increase		Decrease
	(in thousands)
Benefit obligation	$	6,456	$	5,815
Service and interest costs		498		392

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $2.9 million, $2.8 million, and $2.7 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.

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Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric, including three co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation relating to the Company’s Plants Watson and Greene County. In early 2000, the EPA filed a motion to amend its complaint to add the allegations in its notices of violation and to add the Company as a defendant. However, in March 2001, the court denied the motion based on lack of jurisdiction and the EPA has not refiled. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in any one of these matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Environmental Remediation

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled the Company’s transformers as well as those of many other entities. The site owner is now in bankruptcy and the State of Texas has entered into an agreement with the Company and several other utilities to investigate and remediate the site. Amounts expensed during 2003, 2004, and 2005 related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final outcome of this matter to the Company will depend upon further environmental assessment and the ultimate number of potentially responsible parties and cannot now be determined. The remediation expenses incurred by the Company are expected to be recovered through the Company’s ECO Plan.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of

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the default cost-based rates, pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $5.7 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales to the Company through December 31, 2005 is not expected to exceed $7.4 million, of which $4.4 million relates to sales inside the service territory as discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

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Right of Way Litigation

Southern Company and certain of its subsidiaries, including the Company, Georgia Power, Gulf Power, and Southern Telecom, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants.

     To date, the Company has entered into agreements with plaintiffs in approximately 90 percent of the actions pending against the Company to clarify the Company’s easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit) and dismissals of the related cases are in progress. These agreements have not had any material impact on the Company’s financial statements.

     In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, and Southern Telecom, were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Retail Regulatory Matters

Performance Evaluation Plan

The Company’s retail base rates are set under Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi PSC. PEP was designed with the objective that PEP would reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability.

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

     In addition, the Mississippi PSC also approved the Company’s requested changes to PEP, including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes will be limited to four percent of retail revenues annually under the revised PEP. The Mississippi PSC will review all aspects of PEP in 2007. PEP will remain in effect until the Mississippi PSC modifies, suspends, or terminates the plan.

     In December 2005, the Company submitted its annual PEP filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, the Company has requested that the Mississippi PSC approve a temporary change to allow them to exceed this cap as a result of the ongoing effects of Hurricane Katrina. The Company has requested a 5 percent increase in total retail revenues or $32 million retail base revenue increase to become

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effective in April 2006 if approved. Hearings are scheduled for March 2, 2006. The final outcome of this matter cannot now be determined.

Environmental Compliance Overview Plan

The Company’s Environmental Compliance Overview (ECO) Plan establishes procedures to facilitate the Mississippi PSC’s overview of the Company’s environmental strategy and provides for recovery of costs (including cost of capital) associated with environmental projects approved by the Mississippi PSC. Under the ECO Plan, any increase in the annual revenue requirement is limited to two percent of retail revenues. However, the ECO Plan also provides for carryover of any amount over the two percent limit into the next year’s revenue requirement. The Company conducts studies, when possible, to determine the extent of any required environmental remediation. Should such remediation be determined to be probable, reasonable estimates of costs to clean up such sites are developed and recognized in the financial statements. In accordance with the Mississippi PSC order, the Company recovers such costs under the ECO Plan as they are incurred. The Company’s 2005 ECO Plan filing was approved, as filed, by the Mississippi PSC on April 18, 2005 and resulted in a slight increase in rates effective May 2005.

Storm Damage Cost Recovery

The Company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. The Company’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.

     In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The Company sustained significant damage to its distribution and transmission facilities. The Company’s Plant Watson was also damaged. Plant Watson has six generating units, including three gas-fire units totaling 262 megawatts (MW), two coal-fired units totaling 750 MW, and a 40 MW gas turbine. Both of the coal-fired units at the plant have been returned to service. The gas units operate primarily to serve summer peak loads. Repairs to the gas units are expected to be completed by June 1, 2006.

     Prior to Hurricane Katrina, the Company had a balance of approximately $3 million in its property reserve. Incremental Hurricane Katrina restoration costs are currently estimated to total approximately $277 million, net of approximately $68 million of insurance proceeds. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 of the Company’s customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.

     The Mississippi PSC issued an Interim Accounting Order on October 21, 2005, requiring the Company to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital related expenditures. Total Hurricane Katrina costs incurred through December 31, 2005 include approximately $132.6 million of operations and maintenance expenditures and approximately $148.8 million of capital-related expenditures. The cash portions are included in the Statement of Cash Flow under Hurricane Katrina Accounts Payable, Property Additions, and Cost of Removal, net of Salvage and totaled approximately $82.1 million, $81.7 million, and $18.4 million, respectively. On December 7, 2005 the Company filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. The Company is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to proposed state legislation to allow securitized financing and federal grant assistance.

4. JOINT OWNERSHIP AGREEMENTS

The Company and Alabama Power own, as tenants in common, Units 1 and 2 with a total capacity of 500 megawatts at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power.

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Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 with a total capacity of 1,000 MW at Plant Daniel, which is located in Mississippi and operated by the Company.

     At December 31, 2005, the Company’s percentage ownership and investment in these jointly owned facilities were as follows:

Generating	Percent			Gross		Accumulated
Plant	Ownership			Investment		Depreciation
	(in thousands)
Greene County
Units 1 and 2		40	%	$	73,722	$	40,172
Daniel
Units 1 and 2		50	%	$	255,712	$	129,510

     The Company’s proportionate share of plant operating expenses is included in the statements of income.

5. INCOME TAXES

Southern Company and its subsidiaries file a consolidated federal income tax return and combined income tax returns for the State of Alabama and the State of Mississippi. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

     At December 31, 2005, the tax-related regulatory assets and liabilities were $10.4 million and $20.6 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits.

     Details of the federal and state income tax provisions are shown below:

	2005			2004		2003
	(in thousands)
Federal —
Current	$	(61,933	)	$	3,700	$	46,116
Deferred		102,659			40,350		(6,166	)
		40,726			44,050		39,950
State —
Current		(10,009	)		2,542		7,761
Deferred		15,657			4,074		(2,396	)
		5,648			6,616		5,365
Total	$	46,374		$	50,666	$	45,315

     The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in thousands)
Deferred tax liabilities:
Accelerated depreciation	$	269,188		$	224,353
Basis differences		8,630			14,092
Fuel clause under recovered		41,627			8,696
Other		59,883			22,382
Total		379,328			269,523
Deferred tax assets:
Federal effect of state deferred taxes		13,642			7,639
Other property basis differences		9,244			9,762
Pension and other benefits		13,473			12,756
Property insurance		3,618			4,108
Unbilled fuel		7,660			6,225
Other comprehensive loss		2,441			2,322
Other		44,961			62,651
Total		95,039			105,463
Total deferred tax liabilities, net		284,289			164,060
Portion included in prepaid (accrued) income taxes, net		(17,660	)		3,285
Accumulated deferred income taxes in the balance sheets	$	266,629		$	167,345

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     In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.2 million in each year presented. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

     The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred dividends as a result of the following:

	2005			2004			2003
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		3.0			3.3			2.9
Non-deductible book Depreciation		0.5			0.4			0.4
Other		(0.5	)		(0.1	)		(0.8	)
Effective income tax rate		38.0	%		38.6	%		37.5	%

6. FINANCING

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

The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investment and preferred security sale were loaned back to the Company through the issuance of junior subordinated notes totaling $36 million, which constitute substantially all assets of the trust and are reflected in the balance sheets as Long-term Debt Payable to Affiliated Trust (including Securities Due Within One Year). The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust’s payment obligations with respect to these securities. At December 31, 2005, preferred securities of $35 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for the trust and the related securities.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2005 was $82.7 million.

Assets Subject to Lien

In June 2005, the Company’s first mortgage bond indenture was defeased. In December 2005, the remaining outstanding first mortgage bonds were retired by the first mortgage bond trustee. As a result, there are no longer any liens on the Company’s property and the Company no longer has to comply with the covenants and restrictions of the first mortgage bond indenture.

Bank Credit Arrangements

At the beginning of 2006, the Company had total committed credit agreements with banks for approximately $326 million, and $276 million remained unused. Of the total, $101 million expires in 2006 and $225 million in 2008. The Company expects to renew its credit facilities, as needed, prior to expiration. Some of the 2006 agreements allow short-term borrowings to be converted into term loans.

     In connection with these credit arrangements, the Company agrees to pay commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees are 1/8 of 1 percent or less for the Company. Compensating balances are not legally restricted from withdrawal.

     This $276 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2005, the Company had $152 million outstanding in commercial notes. The credit arrangements also provide support to the Company’s variable daily rate tax-exempt pollution control bonds totaling $40 million.

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     During 2005, the peak amount outstanding for short-term debt was $154 million and the average amount outstanding was $42 million. The average annual interest rate on short-term debt was 3.85 percent in 2005.

Financial Instruments

The Company also enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs with the approval of the Mississippi PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2005, 2004, or 2003.

     In addition, at the instruction of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2005, exposure from these activities was not material to the Company’s financial statements.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	27,463
Other comprehensive income		(342	)
Net income		(15	)
Total fair value	$	27,106

     The fair value gains or losses for cash flow hedges are recorded as regulatory assets and liabilities if they are recoverable through the regulatory clauses, otherwise they are recorded in other comprehensive income, and are recognized in earnings at the same time the hedged items affect earnings. For the year 2006, approximately $0.3 million of pre-tax losses are expected to be reclassified from other comprehensive income to fuel expense. The Company has energy-related hedges in place up to and including 2008.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $126 million in 2006, of which $30 million is related to Hurricane Katrina restoration, $112 million in 2007, and $139 million in 2008. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generation assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment and materials; and cost of capital. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program. The Company has no generating plants under construction. Capital improvements to generating, transmission, and distribution facilities, including those to meet environmental standards, will continue.

Long-Term Service Agreements

The Company has entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the leased combined cycle units at Plant Daniel. The LTSA provides that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract.

     In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE are made monthly based on estimated operating hours of the units and are recognized as expense based on actual hours of operation. The Company has recognized $7.9 million, $9.0 million, and $6.0 million for 2005, 2004, and 2003, respectively, which is included in maintenance expense in the statements of income. Remaining payments to GE under this agreement are currently estimated to total $152 million over the next 12 years. However, the LTSA contains various cancellation provisions at the option of the Company.

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     The Company also has entered into a LTSA with ABB Power Generation Inc. (ABB) for the purpose of securing maintenance support for its Chevron Unit 5 combustion turbine plant. In summary, the LTSA stipulates that ABB will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. ABB is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract.

     In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to ABB are made at various intervals based on actual operating hours of the unit. Payments to ABB under this agreement are currently estimated to total $3.0 million over the remaining term of the agreement, which is approximately fifteen months. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to ABB prior to the performance of any planned maintenance are recorded as a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

Fuel Commitments

To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2005. Total estimated minimum long-term obligations at December 31, 2005 were as follows:

Year	Natural Gas		Coal
	(in thousands)
2006	$	168,311	$	184,342
2007		86,978		64,138
2008		50,831		18,552
2009		5,938		—
2010		5,938		—
2011 and thereafter		42,269		—
Total commitments	$	360,265	$	267,032

     Additional commitments for fuel will be required to supply the Company’s future needs.

     SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and the other retail operating companies, Southern Power, and Southern Company Gas. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company Gas as a contracting party under these agreements.

II-280

NOTES (continued)
Mississippi Power Company 2005 Annual Report

Operating Leases

Railcar Leases

The Company and Gulf Power have jointly entered into operating lease agreements for the use of 745 aluminum railcars. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. The Company also has multiple operating lease agreements for the use of an additional 120 aluminum railcars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel.

     The Company’s share (50 percent) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $3.0 million in 2005 and $1.9 million in 2004 and 2003. The Company’s annual lease payments for 2006 through 2010 will average approximately $3.2 million and after 2011, lease payments total in aggregate approximately $4.2 million.

     In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson. The Company’s share (50 percent at Plant Daniel and 100 percent at Plant Watson) of these leases was charged to fuel handling expense in the amount of $611,000 in 2005. The Company’s annual lease payments for 2006 through 2010 will average approximately $693,000 and after 2011, lease payments total in aggregate approximately $52,000.

Plant Daniel Combined Cycle Generating Units

In May 2001, the Company began the initial 10-year term of the lease agreement for a 1,064 megawatt natural gas combined cycle generating facility built at Plant Daniel (Facility). The Company entered into this transaction during a period when retail access was under review by the Mississippi PSC. The lease arrangement provided a lower cost alternative to its cost based rate regulated customers than a traditional rate base asset. See Note 3 under “Retail Regulatory Matters – Performance Evaluation Plan” for a description of the Company’s formula rate plan.

     In 2003, the Facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with the Company. Simultaneously, Juniper entered into a restructured lease agreement with the Company. Juniper has also entered into leases with other parties unrelated to the Company. The assets leased by the Company comprise less than 50 percent of Juniper’s assets. The Company is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease agreement is treated as an operating lease for accounting purposes, as well as for both retail and wholesale rate recovery purposes. For income tax purposes, the Company retains tax ownership. The initial lease term ends in 2011 and the lease includes a purchase and renewal option based on the cost of the Facility at the inception of the lease, which was $370 million. The Company is required to amortize approximately four percent of the initial acquisition cost over the initial lease term. Eighteen months prior to the end of the initial lease, the Company may elect to renew for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17 percent of the initial completion cost over the renewal period. Upon termination of the lease, at the Company’s option, it may either exercise its purchase option or the Facility can be sold to a third party.

     The lease provides for a residual value guarantee, approximately 73 percent of the acquisition cost, by the Company that is due upon termination of the lease in the event that the Company does not renew the lease or purchase the Facility and that the fair market value is less than the unamortized cost of the Facility. A liability of approximately $11 million and $13 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31, 2005 and 2004, respectively. In 2003, approximately $11 million in lease termination costs and were included in other operation expense. Lease expenses were $27 million, $27 million, and $26 million in 2005, 2004, and 2003, respectively.

II-281

NOTES (continued)
Mississippi Power Company 2005 Annual Report

     The Company estimates that its annual amount of future minimum operating lease payments under this arrangement, exclusive of any payment related to the residual value guarantee, as of December 31, 2005, are as follows:

Year	Lease Payments
	(in thousands)
2006	$	28,824
2007		28,718
2008		28,616
2009		28,504
2010		28,398
2011 and thereafter		28,291
Total commitments	$	171,351

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2005, 275 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2003 to 2005 for the options granted to the Company’s employees under the stock option plan is summarized below:

				Average
	Shares			Option
	Subject			Price
	to Option			per Share
Balance at December 31, 2002		1,484,009		$	19.86
Options granted		336,450			27.98
Options canceled		(2,882	)		24.64
Options exercised		(269,753	)		16.35
Balance at December 31, 2003		1,547,824			22.23
Options granted		309,043			29.50
Options canceled		(1,395	)		19.87
Options exercised		(260,061	)		17.00
Balance at December 31, 2004		1,595,411			24.49
Options granted		272,813			32.71
Options canceled		(1,314	)		29.81
Options exercised		(422,472	)		21.67
Balance at December 31, 2005		1,444,438		$	26.86
Options exercisable:
At December 31, 2003		794,374
At December 31, 2004		1,019,627
At December 31, 2005		920,511

II-282

NOTES (continued)
Mississippi Power Company 2005 Annual Report

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares(in thousands)		191		679		575
Average remaining life(in years)		4.1		5.5		8.2
Average exercise price	$	17.67	$	25.93	$	31.02
Exercisable:
Shares(in thousands)		191		594		136
Average exercise price	$	17.67	$	25.64	$	29.66

9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2005 and 2004 are as follows:

					Net Income
					After Dividends
	Operating		Operating		On Preferred
Quarter Ended	Revenues		Income		Stock
	(in thousands)
March 2005	$	215,210	$	31,902	$	16,947
June 2005		248,576		43,061		25,632
September 2005		277,907		51,975		28,244
December 2005		228,040		7,502		2,985
March 2004	$	209,728	$	31,600	$	17,319
June 2004		232,785		43,290		21,891
September 2004		258,564		61,744		35,581
December 2004		209,249		9,607		2,010

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

II-283

SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Mississippi Power Company 2005 Annual Report

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

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Mississippi Power Company 2005 Annual Report

	2005		2004		2003		2002		2001
Operating Revenues (in thousands) :
Residential	$	209,546	$	199,242	$	180,978	$	186,522	$	164,716
Commercial		213,093		199,127		175,416		181,224		163,253
Industrial		190,720		180,516		154,825		164,042		156,525
Other		5,501		5,428		5,082		5,039		4,659
Total retail		618,860		584,313		516,301		536,827		489,153
Sales for resale — non-affiliates		283,413		265,863		249,986		224,275		204,623
Sales for resale — affiliates		50,460		44,371		26,723		46,314		85,652
Total revenues from sales of electricity		952,733		894,547		793,010		807,416		779,428
Other revenues		17,000		15,779		76,914		16,749		16,637
Total	$	969,733	$	910,326	$	869,924	$	824,165	$	796,065
Kilowatt-Hour Sales (in thousands) :
Residential		2,179,756		2,297,110		2,255,445		2,300,017		2,162,623
Commercial		2,725,274		2,969,829		2,914,133		2,902,291		2,840,840
Industrial		3,798,477		4,235,290		4,111,199		4,161,902		4,275,781
Other		37,905		40,229		39,890		39,635		41,009
Total retail		8,741,412		9,542,458		9,320,667		9,403,845		9,320,253
Sales for resale — non-affiliates		4,811,250		6,027,666		5,874,724		5,380,145		5,011,212
Sales for resale — affiliates		896,361		1,053,471		709,065		1,586,968		2,952,455
Total		14,449,023		16,623,595		15,904,456		16,370,958		17,283,920
Average Revenue Per Kilowatt-Hour (cents) :
Residential		9.61		8.67		8.02		8.11		7.62
Commercial		7.82		6.70		6.02		6.24		5.75
Industrial		5.02		4.26		3.77		3.94		3.66
Total retail		7.08		6.12		5.54		5.71		5.25
Sales for resale		5.85		4.38		4.20		3.88		3.64
Total sales		6.59		5.38		4.99		4.93		4.51
Residential Average Annual Kilowatt-Hour Use Per Customer		14,111		14,357		14,161		14,453		13,634
Residential Average Annual Revenue Per Customer	$	1,367	$	1,245	$	1,136	$	1,172	$	1,038
Plant Nameplate Capacity Ratings (year-end) (megawatts)		3,156		3,156		3,156		3,156		3,156
Maximum Peak-Hour Demand (megawatts) :
Winter		2,178		2,173		2,458		2,311		2,249
Summer		2,493		2,427		2,330		2,492		2,466
Annual Load Factor (percent)		56.6		62.4		60.5		61.8		60.7
Plant Availability Fossil-Steam (percent) :		82.8		91.4		92.6		91.7		92.8
Source of Energy Supply (percent) :
Coal		58.1		55.7		57.7		50.8		52.0
Oil and gas		24.4		25.5		19.9		37.7		35.9
Purchased power —
From non-affiliates		5.1		6.4		3.5		3.1		3.1
From affiliates		12.4		12.4		18.9		8.4		9.0
Total		100.0		100.0		100.0		100.0		100.0

II-285

SAVANNAH ELECTRIC AND POWER COMPANY

FINANCIAL SECTION

II-286

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Savannah Electric and Power Company:

We have audited the accompanying balance sheets and statements of capitalization of Savannah Electric and Power Company (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements (pages II-306 to II-329) present fairly, in all material respects, the financial position of Savannah Electric and Power Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

     As discussed in Note 3 to the financial statements, on December 13, 2005, the Company’s Board approved the merger with Georgia Power Company, subject to regulatory approval.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

II-287

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Savannah Electric and Power Company 2005 Annual Report

OVERVIEW

Business Activities

Savannah Electric and Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia.

     Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the Company’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, and rising fuel prices. In 2005, the Company completed a retail base rate case and a retail fuel cost recovery rate case. These regulatory actions are expected to benefit future earnings stability, to help enable the recovery of substantial capital investments in generating plant, to facilitate the continued reliability of the transmission and distribution network, and to allow for the recovery of increasing fuel costs. In connection with the merger, as discussed below, additional rate actions are expected to be completed in 2006.

Merger with Georgia Power

On December 13, 2005, the Company entered into a merger agreement with Georgia Power Company (Georgia Power) under which the Company will merge into Georgia Power, with Georgia Power continuing as the surviving corporation (the Merger). The Merger must be approved by Savannah Electric’s preferred shareholders and is subject to the receipt of regulatory approval of the Federal Energy Regulatory Commission (FERC), the Georgia Public Service Commission (PSC), and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to occur by July 2006. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Merger” herein and Note 3 under “Retail Regulatory Matters — Merger” for additional information.

Key Performance Indicators

In striving to maximize shareholder value while providing cost effective energy to more than 147,000 customers, the Company focuses on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income. The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR excludes the impact of hurricanes and certain outage events caused by manufacturer defects. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, normal weather conditions, and expected capital expenditures. The 2005 performance was on target on these reliability measures. Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal.

     The Company’s 2005 results compared to its targets for some of its key indicators are reflected in the following chart.

Key	2005	2005
Performance Indicator	Target Performance	Actual Performance
Customer Satisfaction	Top quartile in customer surveys	Second quartile
Peak Season EFOR	3.0% or less	1.0%
Net Income	$25.2 million	$29.9 million

     The failure to achieve top quartile in customer satisfaction is believed to have been the result of three rate increases since November 2004, which was a significant consideration in the Merger decision. The financial performance and Peak Season EFOR achieved in 2005 reflect the focus management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

II-288

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

Earnings

The Company’s net income after preferred stock dividends for 2005 totaled $29.9 million, representing an increase of $5.7 million, or 23.5 percent, from the prior year. Higher operating revenues resulting from the base rate increase in June 2005, as well as increases in transmission revenues and other income were somewhat offset by higher operating expenses and higher interest expense resulting from additional securities outstanding and higher interest rates. Earnings were $24.2 million in 2004, reflecting an increase of $0.8 million, or 3.3 percent, from the prior year. Higher operating revenues from customer growth were somewhat offset by higher operating expenses and higher interest expenses resulting from additional securities outstanding. In 2003, earnings were $23.5 million, representing an increase of $2.1 million, or 10.0 percent, from the prior year. Higher operating revenues, lower depreciation and amortization expenses, and lower interest expenses were somewhat offset by higher operating expenses and income taxes.

RESULTS OF OPERATIONS

A condensed income statement is as follows:

				Increase (Decrease)
	Amount			from Prior Year
	2005			2005		2004			2003
				(in thousands)
Operating revenues	$	444,994		$	88,034	$	41,843		$	18,111
Fuel		106,549			50,553		119			922
Purchased power		146,247			20,573		36,169			13,901
Other operation and maintenance		93,014			7,049		2,344			2,603
Depreciation and amortization		22,404			1,152		753			(2,205	)
Taxes other than income taxes		16,202			957		580			208
Total operating expenses		384,416			80,284		39,965			15,429
Operating income		60,578			7,750		1,878			2,682
Total other income and (expense)		(10,956	)		1,762		(745	)		3,528
Income taxes		16,989			2,611		(1,140	)		4,070
Net income		32,633			6,901		2,273			2,140
Dividends on preferred stock		2,700			1,200		1,500			—
Net income after dividends on preferred stock	$	29,933		$	5,701	$	773		$	2,140

Revenues

Details of operating revenues are as follows:

	Amount
	2005			2004			2003
			(in thousands)
Retail — prior year	$	341,766		$	298,807		$	283,225
Change in —
Base rates		6,097			—			2,799
Sales growth		1,696			9,497			2,084
Weather		1,127			10			(263	)
Fuel cost recovery and other		70,865			33,452			10,962
Retail — current year		421,551			341,766			298,807
Sales for resale —
Non-affiliates		5,126			5,035			5,653
Affiliates		10,536			6,130			6,499
Total sales for resale		15,662			11,165			12,152
Other operating revenues		7,781			4,029			4,158
Total operating revenues	$	444,994		$	356,960		$	315,117
Percent change		24.7	%		13.3	%		6.1	%

     Total operating revenues for 2005 were $445.0 million, reflecting a 24.7 percent increase when compared to 2004. Retail revenues increased 23.3 percent, or $79.8 million, in 2005, increased 14.4 percent, or $43.0 million, in 2004, and increased 5.5 percent, or $15.6 million, in 2003. On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for the Company ending May 31, 2008 (2005 Retail Rate Plan). Retail base rates also increased in June 2002. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.

     Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Under the fuel recovery provisions, fuel revenues generally equal fuel expenses—including the fuel component of purchased energy—and do not affect net income. The Georgia PSC approved a Fuel Cost Recovery (FCR) rate increase that became effective in December 2005. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein and Notes 1 and 3 to the financial statements under “Fuel Costs” and “Retail Regulatory Matters —Fuel Cost Recovery,” respectively, for additional information.

     Revenues from sales to non-affiliated utilities are primarily energy related. These sales do not have a

II-289

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

significant impact on net income since the energy is generally sold at variable cost.

     Sales to affiliated companies vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliated sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These energy sales do not have a significant impact on earnings since the energy is generally sold at variable cost.

Energy Sales

Changes in revenues are influenced heavily by the amount of energy sold each year. Kilowatt-hour (KWH) sales for 2005 and the percent change by year were as follows:

	KWH		Percent Change
	2005		2005			2004			2003
	(in millions)
Residential		1,923		1.3	%		8.3	%		(0.1	)%
Commercial		1,566		1.7			5.4			0.4
Industrial		805		(4.2	)		(2.4	)		8.8
Other		136		(4.7	)		4.1			(0.5	)
Total retail		4,430		0.2			5.0			1.8
Sales for resale —
Non-affiliates		84		(36.1	)		(19.2	)		7.7
Affiliates		178		24.8			(22.9	)		47.1
Total		4,692		(0.1	)%		3.0	%		3.3	%

     In 2005, residential and commercial energy sales increased from the prior year primarily due to continued customer growth and favorable weather conditions. Industrial sales were lower as compared to the prior year due to lower usage by several industrial customers resulting from cogeneration, plant outages, and reductions in production.

     In 2004, residential and commercial energy sales increased from the prior year primarily due to continued customer growth. Industrial sales were lower than the prior year because of lower usage by several industrial customers due to cogeneration and cutbacks in production.

     In 2003, residential sales decreased from the prior year primarily due to weather-related demand. Industrial sales were higher than the prior year because of an increase in usage by several industrial customers, reflecting the beginning of an economic recovery from the previous two-year slowdown. All three customer classes benefited from continued customer growth.

     Energy sales to retail customers are projected to increase at a compound average growth rate of 2.4 percent during the period 2006 through 2010.

Expenses

Fuel and Purchased Power Expenses

Fuel and purchased power costs constitute the single largest expense for the Company. The mix of energy supply is determined primarily by demand, the unit cost of fuel consumed, and the availability and cost of generation units.

     The amount and sources of generation, the average cost of fuel per net KWH generated, and the amount and average cost of purchased power were as follows:

	2005		2004		2003
Total generation (millions of KWHs)		2,569		2,135		2,325
Sources of generation (percent) —
Coal		79		96		94
Oil		1		1		2
Gas		20		3		4
Average cost of fuel per net KWH generated (cents)		4.15		2.62		2.40
Total purchased power (millions of KWHs)		2,472		2,829		2,581
Average cost of purchased power per net KWH (cents)		5.92		4.44		3.47

     Fuel expense increased 90.3 percent in 2005 as compared to 2004 due to a 58.4 percent increase in the average cost of fuel per net KWH generated and a 20.3 percent increase in generation due to the commercial operation of the Plant McIntosh Combined Cycle Units 10 and 11 in June 2005. In 2004, fuel expense increased 0.2 percent over the prior year due to a 9.2 percent increase in the average cost of fuel per net KWH generated that more than offset an 8.2 percent decrease in generation. In 2003, fuel expense increased 1.7 percent as compared to the prior year due to a slight increase in generation offset somewhat by a lower cost of coal.

     Purchased power expense increased $20.6 million, or

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16.4 percent, in 2005 as compared to 2004 resulting from the increases in fuel costs which drove higher energy costs. In 2004, purchased power expense increased $36.2 million, or 40.4 percent over the prior year due to increased energy demands and higher energy costs. In 2003, purchased power expense increased $13.9 million, or 18.4 percent, over the prior year due to increased energy demands and a purchased power agreement (PPA) between the Company and Southern Power for energy and capacity from Plant Wansley Units 6 and 7 which began in June 2002.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as increased mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions.

Other Operating Expenses

Other operation and maintenance expenses increased $7.0 million, or 8.2 percent, in 2005 over the prior year primarily due to increases of $4.0 million in production expenses related to scheduled maintenance outages at both Plant Kraft and Plant McIntosh, $1.4 million in transmission expenses related in part to a transformer failure and new transmission facilities agreements, $0.6 million in distribution expenses related to tree trimming, and increases of $0.5 million in administrative and general expenses primarily related to employee benefits expenses and Sarbanes-Oxley related accounting activities, offset partially by a decrease of $0.7 million in the storm damage accrual as ordered in the 2005 Retail Rate Plan.

     In 2004, other operation and maintenance expenses increased $2.3 million, or 2.8 percent over the prior year, as a result of a $2.8 million increase in administrative and general expenses, primarily relating to accounting and auditing services and employee benefits expense, and a $0.6 million increase in distribution expenses partially offset by a decrease of $1.4 million in maintenance expense due to a scheduled turbine maintenance outage at Plant Kraft in 2003.

     In 2003, other operation and maintenance expenses increased $2.6 million, or 3.2 percent, over the prior year. Administrative and general expenses increased by $1.0 million primarily due to increases in accounting and auditing services, insurance reserves, and employee benefits expense, somewhat offset by the annual true-up in billings to Georgia Power for charges associated with the jointly owned combustion turbines at the Company’s Plant McIntosh. Maintenance expense increased $1.5 million primarily due to a scheduled turbine maintenance outage at Plant Kraft and higher transmission and distribution maintenance expenses.

     Depreciation and amortization increased $1.2 million, or 5.4 percent, in 2005 over the prior year due to the completion of the amortization of the regulatory liability for accelerated depreciation in May 2005 in accordance with the 2002 Georgia PSC rate order and the addition of the McIntosh combined cycle facilities in June 2005 partially offset by lowering the composite depreciation rate as part of the 2005 Retail Rate Plan. In 2004, depreciation and amortization increased $0.8 million, or 3.7 percent, from the prior year due to an increase in depreciable property. Depreciation and amortization decreased $2.2 million, or 9.7 percent, in 2003 from the prior year primarily as a result of discontinuing accelerated depreciation and beginning amortization of the related regulatory liability in June 2002. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

Other Income (Expense), Net

Other income increased in 2005 over the prior year as a result of a $2.6 million gain on the settlement of gas hedges, as allowed by the Georgia PSC, and a $2.5 million disallowance of Plant McIntosh construction costs recorded in December 2004. These increases were partially offset by $0.9 million in expenses associated with the Company’s non-qualified benefit plans in connection with the Merger. In 2004, other income decreased over the prior year due to the Plant McIntosh disallowance. Other income increased in 2003 over the prior year as a result of a distribution of the proceeds

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from the sale of a mutual life insurance company in which the Company held policies used to fund its non-qualified benefit plans. See Notes 2 and 3 to the financial statements under “Retail Regulatory Matters — Fuel Hedging Program” and — “Plant McIntosh Construction Project” for additional information.

Non-Operating Expenses

In 2005, interest expense and preferred dividends increased $3.9 million, or 29.0 percent, over the prior year due to the issuance of senior notes and preferred stock in 2004, as well as an increase in short-term borrowings and higher interest rates. Interest expense and preferred dividends increased $4.0 million, or 41.3 percent, in 2004 over the prior year primarily related to an increase in senior notes and preferred stock outstanding. These increases were partially offset by a decrease in distributions on mandatorily redeemable preferred securities due to the redemption of $40 million of mandatorily redeemable preferred securities. Interest expense decreased $2.0 million, or 17.4 percent, in 2003 from the prior year primarily as a result of a lower principal amount of debt outstanding during the year. Lower interest rates also contributed to lower expenses in 2003. See FINANCIAL CONDITION AND LIQUIDITY — “Financing Activities” herein for additional information.

Effects of Inflation

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

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail customers within the traditional service area of southeastern Georgia. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Regulatory Matters” and “FERC Matters” for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors. These factors include the Company’s ability to maintain a stable regulatory environment that continues to allow for the recovery of all prudently incurred costs. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the Company’s service area.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added the Company as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District

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Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plant Kraft. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and the Company has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions” for additional information.

     The Company believes it complied with applicable laws and the EPA’s regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Environmental Statutes and Regulations

General

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Resource

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Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, the Company had invested approximately $10.8 million in capital projects to comply with these requirements, with annual totals of $1.5 million, $3.4 million, and $0.7 million for 2003, 2004, and 2005, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $31.2 million, including $0.6 million and $4.5 million for 2006 and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect the Company. New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Through 2005, the Company had spent approximately $2.8 million in reducing nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional measures are under consideration to further reduce SO₂ and NOx emissions, to maintain compliance with existing regulations and to meet new requirements.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. During 2005, the EPA’s fine particulate matter nonattainment designations also became effective for several areas across the United States. No areas within the Company’s service area, however, have been designated as nonattainment under either the eight-hour ozone standard or the fine particulate matter standard. Although the State of Georgia was originally included in the states subject to the regional NO_x rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NO_x reduction rules for the State of Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of its state implementation plan.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including Georgia, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions may be accomplished by the installation of additional emission controls at the Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and

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reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule, and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies and therefore, cannot now be determined.

Environmental Remediation

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in the financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change, and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010 — 2012. Southern Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

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FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. Through Southern Company Services, Inc. (SCS), as agent, the Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and the Company be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is to vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

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Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Transmission

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

PSC Matters

Merger

In connection with the Merger, Georgia Power and the Company plan to establish a new coastal regional organization for Georgia Power that will operate following completion of the Merger. Management expects that current employees of the Company will fill most of the positions in the new regional organization. In connection with the Merger, the Company plans to offer voluntary severance to a number of employees and expects to incur approximately $16 million in expenses related to severance benefits and termination costs associated with the Company’s Supplemental Executive Retirement Plan. These anticipated severance benefits will result in cash payments that are expected to be expensed during the first half of 2006. The actual amount and timing of these charges may differ materially from the Company’s estimates described above and will depend upon the final composition and seniority of the affected employees and the actual timing of completion of the Merger and the development of the coastal regional organization of Georgia Power.

     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, Georgia Power and the Company filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, Georgia Power and the Company are seeking the approval of the Georgia PSC with respect to the following matters:

• the transfer of the Company’s generating facilities and certification of the generating facilities as Georgia Power assets;

• amendments to Georgia Power’s Integrated Resource Plan to add the current customers and generating facilities of the Company;

• the transfer of the Company’s assigned service territory to Georgia Power;

• adoption of Georgia Power’s service rules and regulations to the current Savannah Electric customers;

• new fuel rate and base rate schedules that would apply to Georgia Power’s sale of electricity to the current company customers; and

• the issuance of additional shares of Georgia Power common stock to Southern Company in exchange for Southern Company’s shares of the Company’s common stock.

     Georgia Power has also requested that the Georgia PSC better align the rates for the Company’s customers with those of Georgia Power. Currently, customers of the Company pay slightly lower base rates and significantly higher fuel rates than Georgia Power customers. The overall effect is that customers of the Company pay substantially higher overall costs for electricity. See “Rate Filing” and “Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

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Rate Filing

In November 2004, the Company filed a rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in total retail revenues, effective January 1, 2005 to cover the cost of new generation and PPAs, higher operating and maintenance expenses, and continued investment in new transmission and distribution facilities to support growth and ensure reliability. The requested increase was based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent.

     On May 17, 2005, the Georgia PSC approved the 2005 Retail Rate Plan. Under the terms of the 2005 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 9.75 percent to 11.75 percent. Two-thirds of any earnings above 11.75 percent will be applied to rate refunds with the remaining one-third retained by the Company. Retail base revenues increased in June 2005 by approximately $9.6 million, or 5.1 percent, on an annual basis. If the Merger is not completed, the Company would be required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued. In connection with the Merger, Georgia Power has requested Georgia PSC approval of a “merger transition charge” that would be used to adjust the Company’s total base revenues to more closely match the existing base rates for Georgia Power. The merger transition charge would remain in effect until completion of Georgia Power’s next base rate case in 2007 that would be effective on January 1, 2008. See Note 3 to the financial statements under “Retail Regulatory Matters — Merger” for additional information.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and Georgia Power and the Company for capacity from Plant McIntosh Combined Cycle Units 10 and 11, which were then under construction. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet applicable standards for market-based rates between affiliates. To ensure the timely completion of construction and the availability of the units in the summer of 2005 for their retail customers, the Company and Georgia Power in May 2004, requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities.

     Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. See “FERC Matters — Intercompany Interchange Contract” above for additional information.

     In December 2004, the Georgia PSC approved the transfer of the Plant McIntosh construction project, at a total fair market value of approximately $385 million. This value reflected an approximate $16 million disallowance of which approximately $3 million is attributable to the Company and reduced the Company’s 2004 net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Combined Cycle Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. In connection with the Company’s 2005 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates.

Fuel Cost Recovery

On November 10, 2005, the Georgia PSC voted to approve the Company’s request to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs. Fuel revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the customer fuel rates will have no significant effect on the Company’s net income, but is

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expected to increase annual cash flow by approximately $52.4 million.

     As a result of recent increases in fuel costs, the Georgia PSC ordered the Company to file a new fuel case on or before January 17, 2006. In connection with the Merger, the Company requested and the Georgia PSC agreed to postpone the January 2006 filing. Instead, the Company and Georgia Power plan to jointly file a fuel case in March 2006 that would seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined generating fleet. The new fuel cost recovery rate would be paid by all Georgia Power customers following the Merger, including the existing customers of the Company. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups. See “Merger” herein for additional information.

     In a separate proceeding on August 2, 2005, the Georgia PSC initiated an investigation of the Company’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. The Company and Georgia Power are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.

Other Matters

In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers’ Accounting for Pensions, the Company recorded non-cash pension costs of approximately $6.2 million, $5.3 million, and $4.3 million 2005, 2004, and 2003, respectively. Postretirement benefit costs for the Company were approximately $3.0 million in 2005, $2.8 million in 2004, and $2.7 million in 2003. Both pension and postretirement costs are expected to continue to trend upward. Future costs are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

     Effective September 30, 2004, the Company retired Units 4 and 5 at Plant Riverside. The remaining units at the plant were retired on May 31, 2005. These retirements had no material impact on the Company’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

The Company is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

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

Contingent Obligations

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

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

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

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

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

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

Unbilled Revenues

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

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal because the timing of their retirements was dependent on future events. At

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

December 31, 2005, the Company recorded additional asset retirement obligations (and assets) of approximately $3.3 million. The adoption of FIN 47 did not have any effect on the Company’s income statement. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.”

Stock Options

On January 1, 2006, the Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be stable at December 31, 2005. As of December 31, 2005, the Company’s capital structure consisted of 47.7 percent common stockholder’s equity, 8.8 percent preferred stock, and 43.5 percent long-term debt, excluding amounts due within one year.

     The principal change in the Company’s financial condition in 2005 was the addition of $52.3 million to utility plant, the majority of which was related to completion of Plant McIntosh Units 10 and 11. The funds needed for gross property additions are currently provided from operating activities, the issuance of securities, capital contributions from Southern Company, and short-term debt. See statements of cash flows for additional information. The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, including funds from operations and capital contributions from Southern Company. The Company is required to meet certain earnings coverage requirements specified in its mortgage indenture and corporate charter to issue new first mortgage bonds and preferred stock. The Company’s coverage ratios are sufficiently high to permit, at present interest rate levels, any foreseeable security sales. There are no restrictions on the amount of unsecured indebtedness allowed. The amount, type, and timing of any future financings — if needed — will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors.

     The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term securities by the Company is generally subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, the Company files registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933 (the 1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     At the beginning of 2006, the Company had $80 million of unused short-term and revolving credit arrangements with banks to meet its short-term cash needs. Of this amount, $60 million will expire at various times in 2006 and $20 million will expire in 2008. The arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted to the indebtedness of the Company. The Company is currently in compliance with all such covenants. The Company expects to renew, as needed, its credit arrangements prior to expiration. The Company also has adequate cash flow from operating activities and access to the capital markets to meet liquidity needs. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other retail operating companies.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2005, the Company had outstanding $49.9 million in commercial paper and $8.9 million in extendible commercial notes.

     The Company’s committed credit arrangements provide liquidity support to some of the Company’s variable rate obligations and to its commercial paper program. At December 31, 2005, the amount of variable rate obligations outstanding requiring liquidity support was $6.7 million.

     The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

Financing Activities

Maturities and redemptions of long-term debt and mandatorily redeemable preferred securities were $1.1 million in 2005, $71.0 million in 2004, and $39.8 million in 2003. The Company issued no new securities in 2005.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, the Company’s exposure related to these agreements was not material.

Market Price Risk

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

     To mitigate future exposure to change in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as cash flow hedges. The weighted average rate on $6.7 million of variable rate long-term debt outstanding that has not been hedged at January 1, 2006 was 4.04 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, at January 1, 2006, the change would not materially affect annualized interest expense. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

     To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. In addition, the Company has implemented a natural gas/oil hedging program ordered by the Georgia PSC. The program limits the recovery of losses on financial hedging positions through the fuel clause to 10 percent of the Company’s annual natural gas/oil budget. These hedging position limits were $1.1 million for 2003, $2.7 million for 2004, and $5.1 million for 2005 and will be $7.4 million for 2006. The program has operated within the defined hedging position limits set for each year. See Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Hedging Program” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

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

	Changes in Fair Value
	2005			2004
	(in thousands)
Contracts beginning of year	$	1,474		$	463
Contracts realized or settled		(6,895	)		(1,811	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		14,169			2,822
Contracts end of year	$	8,748		$	1,474

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

Source of 2005 Year-End Valuation Prices
	Total			Maturity
	Fair Value			Year 1			2-3 Years
	(in thousands)
Actively quoted	$	8,762		$	6,394		$	2,368
External sources		(14	)		(14	)		—
Models and other methods		—			—			—
Contracts end of year	$	8,748		$	6,380		$	2,368

     Unrealized gains and losses from mark to market adjustments on derivative contracts related to the Company’s fuel hedging program are recorded as regulatory assets and liabilities. Realized gains and losses from this program are included in fuel expense and recovered through the Company’s FCR clause. Of the net gains, the Company is allowed to retain 25 percent in earnings. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. These amounts were not material in any year presented. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	8,752
Other comprehensive income		—
Net income		(4	)
Total fair value	$	8,748

     The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

Capital Requirements and Contractual Obligations

The Company’s construction program is currently estimated to be $44.7 million in 2006, $33.5 million in 2007, and $55.8 million in 2008. Environmental expenditures included in these amounts are $0.6 million in 2006 and $4.4 million for 2008. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Construction of new transmission and distribution facilities and capital improvements for generation, transmission, and distribution facilities, including those needed to meet the environmental standards previously discussed, will be ongoing.

     As discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

Contractual Obligations

			2007-		2009-		After
	2006		2008		2010		2010		Total
	(in thousands)
Long-term debt(a) —
Principal	$	21,003	$	47,020	$	1,366	$	168,647	$	238,036
Interest		13,294		23,677		17,585		139,187		193,743
Commodity derivative obligations(b)		901		2		—		—		903
Preferred stock dividends(c)		2,700		5,400		5,400		—		13,500
Operating leases		909		1,573		1,077		3,179		6,738
Purchase commitments(d) —
Capital(e)		44,696		89,261		—		—		133,957
Coal		60,615		11,073		—		—		71,688
Natural gas(f)		60,829		51,288		87,886		362,804		562,807
Purchased power		13,240		26,531		13,286		—		53,057
Long-term service agreements		1,212		3,146		4,280		27,223		35,861
Postretirement benefit trusts(g)		1,300		2,600		—		—		3,900
Total	$	220,699	$	261,571	$	130,880	$	701,040	$	1,314,190

(a)	All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
(b)	For additional information, see Notes 1 and 6 to the financial statements herein.
(c)	Preferred stock does not mature; therefore, amounts are provided for the next five years only. In connection with the Merger, the Company’s preferred stock is expected to be exchanged for Georgia Power preferred stock.
(d)	The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $93.0 million, $86.0 million, and $83.6 million, respectively.
(e)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)	Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)	The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Information

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, earnings growth, completion of construction projects, estimated construction and other expenditures, financing activities, access to sources of capital, the merger of the Company and Georgia Power, impacts of the adoption of new accounting rules, and the Company’s projections for postretirement benefit trust contributions. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company and FERC matters;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

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

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

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

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

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

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

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

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

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

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

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STATEMENTS OF INCOME

For the Years Ended December 31, 2005, 2004, and 2003

Savannah Electric and Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Revenues:
Retail sales	$	421,551		$	341,766		$	298,807
Sales for resale —
Non-affiliates		5,126			5,035			5,653
Affiliates		10,536			6,130			6,499
Other revenues		7,781			4,029			4,158
Total operating revenues		444,994			356,960			315,117
Operating Expenses:
Fuel		106,549			55,996			55,877
Purchased power —
Non-affiliates		12,470			11,413			5,713
Affiliates		133,777			114,261			83,792
Other operations		62,718			61,134			56,823
Maintenance		30,296			24,831			26,798
Depreciation and amortization		22,404			21,252			20,499
Taxes other than income taxes		16,202			15,245			14,665
Total operating expenses		384,416			304,132			264,167
Operating Income		60,578			52,828			50,950
Other Income and (Expense):
Interest income		255			208			290
Interest expense, net of amounts capitalized		(14,778	)		(12,047	)		(9,590	)
Distributions on mandatorily redeemable preferred securities		—			(109	)		(2,740	)
Other income (expense), net		3,567			(770	)		67
Total other income and (expense)		(10,956	)		(12,718	)		(11,973	)
Earnings Before Income Taxes		49,622			40,110			38,977
Income taxes		16,989			14,378			15,518
Net Income		32,633			25,732			23,459
Dividends on Preferred Stock		2,700			1,500			—
Net Income After Dividends on Preferred Stock	$	29,933		$	24,232		$	23,459

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

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2005, 2004, and 2003

Savannah Electric and Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Activities:
Net income	$	32,633		$	25,732		$	23,459
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		24,698			23,710			22,587
Deferred income taxes and investment tax credits, net		25,792			13,441			654
Allowance for equity funds used during construction		(2,337	)		(2,379	)		(193	)
Pension, postretirement, and other employee benefits		6,133			4,866			5,312
Tax benefit of stock options		1,552			861			884
Other, net		2,871			(7,758	)		4,261
Changes in certain current assets and liabilities —
Receivables		(62,593	)		(26,432	)		212
Fossil fuel stock		(5,426	)		(1,938	)		(323	)
Materials and supplies		(1,863	)		(842	)		516
Other current assets		175			(5,324	)		4,615
Accounts payable		15,497			5,035			3,713
Accrued taxes		(3,628	)		3,352			(1,131	)
Accrued compensation		340			(40	)		(819	)
Other current liabilities		(174	)		(911	)		(4,492	)
Net cash provided from operating activities		33,670			31,373			59,255
Investing Activities:
Property additions		(48,443	)		(47,677	)		(39,015	)
Purchase of property from affiliates		—			(74,832	)		—
Other		(1,656	)		539			974
Net cash used for investing activities		(50,099	)		(121,970	)		(38,041	)
Financing Activities:
Increase (decrease) in notes payable, net		38,203			20,567			(2,897	)
Proceeds —
Pollution control bonds		—			—			13,870
Senior notes		—			35,000			60,000
Other long-term debt		—			10,000			—
Preferred stock		—			45,000			—
Capital contributions from parent company		442			47,255			6,757
Redemptions —
Pollution control bonds		—			—			(13,870	)
Senior notes		—			—			(20,000	)
Other long-term debt		(1,095	)		(31,014	)		(5,944	)
Mandatorily redeemable preferred securities		—			(40,000	)		—
Payment of preferred stock dividends		(2,700	)		(825	)		—
Payment of common stock dividends		(26,700	)		(23,200	)		(23,000	)
Other		(81	)		(1,267	)		(2,165	)
Net cash provided from financing activities		8,069			61,516			12,751
Net Change in Cash and Cash Equivalents		(8,360	)		(29,081	)		33,965
Cash and Cash Equivalents at Beginning of Year		8,862			37,943			3,978
Cash and Cash Equivalents at End of Year	$	502		$	8,862		$	37,943
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,079, $1,471, and $220 capitalized, respectively)	$	13,358		$	10,080		$	11,334
Income taxes (net of refunds)		(11,042	)		4,581			8,439

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

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BALANCE SHEETS

At December 31, 2005 and 2004

Savannah Electric and Power Company 2005 Annual Report

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

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

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BALANCE SHEETS
At December 31, 2005 and 2004
Savannah Electric and Power Company 2005 Annual Report

Liabilities and Stockholder’s Equity	2005		2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	21,003	$	1,010
Notes payable		58,771		20,567
Accounts payable —
Affiliated		29,840		17,379
Other		19,355		16,166
Customer deposits		7,068		6,973
Accrued taxes —
Income taxes		—		148
Other		1,909		5,390
Accrued interest		3,223		3,050
Accrued compensation		5,952		5,612
Other		15,020		9,426
Total current liabilities		162,141		85,721
Long-term Debt(See accompanying statements)		217,033		237,769
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		119,424		90,079
Deferred credits related to income taxes		7,978		8,738
Accumulated deferred investment tax credits		7,298		7,961
Employee benefit obligations		54,661		46,580
Other cost of removal obligations		40,575		41,890
Other regulatory liabilities		12,107		11,066
Other		10,127		6,693
Total deferred credits and other liabilities		252,170		213,007
Total Liabilities		631,344		536,497
Preferred Stock(See accompanying statements)		43,909		43,938
Common Stockholder’s Equity(See accompanying statements)		237,548		232,156
Total Liabilities and Stockholder’s Equity	$	912,801	$	812,591
Commitments and Contingent Matters(See notes)

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

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STATEMENTS OF CAPITALIZATION
At December 31, 2005 and 2004
Savannah Electric and Power Company 2005 Annual Report

	2005			2004			2005			2004
	(in thousands)						(percent of total)
Long-Term Debt:
First mortgage bonds — 6.9% due May 1, 2006	$	20,000		$	20,000
Long-term notes payable —
6.55% due May 15, 2008		45,000			45,000
4.90% to 5.75% due 2013 through 2044		150,000			150,000
Total long-term notes payable		195,000			195,000
Other long-term debt —
Non-collateralized pollution control revenue bonds —
Variable rates (2.65% to 3.75% at 1/1/06)
due 2016-2038		17,955			17,955
Capitalized lease obligations		5,081			5,824
Total long-term debt (annual interest requirement — $13.3 million)		238,036			238,779
Less amount due within one year		21,003			1,010
Long-term debt excluding amount due within one year		217,033			237,769			43.5	%		46.2	%
Non-Cumulative Preferred Stock:
$25 par value — 6.00%
Authorized — 4,000,000 shares
Outstanding — 1,800,000 shares
(annual dividend requirement — $2.7 million)		43,909			43,938			8.8			8.6
Common Stockholder’s Equity:
Common stock, par value $5 per share —
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares		54,223			54,223
Paid-in capital		74,527			72,533
Retained earnings		110,939			107,685
Accumulated other comprehensive income (loss)		(2,141	)		(2,285	)
Total common stockholder’s equity		237,548			232,156			47.7	%		45.2	%
Total Capitalization	$	498,490		$	513,863			100.0	%		100.0	%

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

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
					(in thousands)
Balance at December 31, 2002	$	54,223	$	16,776		$	106,194		$	(1,244	)	$	175,949
Net income		—		—			23,459			—			23,459
Capital contributions from parent company		—		7,641			—			—			7,641
Other comprehensive income (loss)		—		—			—			(960	)		(960	)
Cash dividends on common stock		—		—			(23,000	)		—			(23,000	)
Balance at December 31, 2003		54,223		24,417			106,653			(2,204	)		183,089
Net income after dividends on preferred stock		—		—			24,232			—			24,232
Capital contributions from parent company		—		48,116			—			—			48,116
Other comprehensive income (loss)		—		—			—			(81	)		(81	)
Cash dividends on common stock		—		—			(23,200	)		—			(23,200	)
Balance at December 31, 2004		54,223		72,533			107,685			(2,285	)		232,156
Net income after dividends on preferred stock		—		—			29,933			—			29,933
Capital contributions from parent company		—		1,994			—			—			1,994
Other comprehensive income (loss)		—		—			—			144			144
Cash dividends on common stock		—		—			(26,700	)		—			(26,700	)
Other		—		—			21			—			21
Balance at December 31, 2005	$	54,223	$	74,527		$	110,939		$	(2,141	)	$	237,548

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

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Savannah Electric and Power Company 2005 Annual Report

	2005			2004			2003
	(in thousands)
Net income after dividends on preferred stock	$	29,933		$	24,232		$	23,459
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(235), $(253) and $(336), respectively		(371	)		(401	)		(533	)
Changes in fair value of qualifying hedges, net of tax of $308, $161 and $(284), respectively		494			255			(450	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $13, $41 and $15, respectively		21			65			23
Total other comprehensive income (loss)		144			(81	)		(960	)
Comprehensive Income	$	30,077		$	24,151		$	22,499
The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Savannah Electric and Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and the Company, provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia. Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and Southern Power, related to jointly owned generating facilities, interconnecting transmission lines, or the exchange of electric power, are regulated by the Federal Energy Regulatory Commission (FERC). SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

     Certain prior years’ data presented in the financial statements has been reclassified to conform with the current year presentation.

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company also is subject to regulation by the FERC and the Georgia Public Service Commission (PSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and employee benefits, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $17.9 million, $17.4 million, and $16.3 million during 2005, 2004, and 2003, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA and management believes they are reasonable.

     The Company has a purchased power agreement (PPA) with Southern Power for 200 megawatts of capacity from Plant Wansley Units 6 and 7 which began operation in June 2002. Purchased power capacity and energy costs in 2005 amounted to $50.7 million. At December 31, 2005, approximately $0.9 million in prepaid capacity expense related to this PPA was recorded in other deferred charges and other assets in the balance sheets.

     The Company operates an eight-unit combustion turbine site at its Plant McIntosh. Two of the units are owned by the Company, and six of the units are owned by Georgia Power. Georgia Power reimburses the Company for its proportionate share of the related expenses, which were $1.9 million in 2005, $3.3 million in 2004, and $3.6 million in 2003.

     In addition, the Company and Georgia Power jointly

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report

acquired, in 2004, the Plant McIntosh Combined Cycle Units 10 and 11 construction project from Southern Power. The Company also operates these units which were placed in service in June 2005. Georgia Power reimburses the Company for its proportionate share of the related expenses, which were $3.6 million for 2005. See Note 3 under “Retail Regulatory Matters — Plant McIntosh Construction Project” and Notes 4 and 5 for additional information.

     The Company provides incidental services to other subsidiaries which are generally minor in duration and amount. However, with the hurricane damage experienced by Alabama Power, Gulf Power, and Mississippi Power in the last two years, assistance provided to aid in storm restoration has caused an increase in these activities. The total amount of storm restoration provided in 2004 and 2005 was $0.5 million and $1.2 million, respectively. These activities were billed at cost.

     The retail operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under “Fuel Commitments” and “Purchased Power Commitments” for additional information.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

     Regulatory assets and (liabilities) reflected in the balance sheets at December 31 and the amortization periods are discussed below as follows:

	2005			2004			Note
	(in thousands)
Asset retirement obligations	$	5,610		$	3,868			(a	)
Deferred income tax charges		11,455			10,588			(a	)
Loss on reacquired debt		7,209			7,935			(b	)
Deferred McIntosh maintenance costs		7,370			8,599			(c	)
Coal transloader		—			3,077			(d	)
Fuel-hedging assets		889			563			(f	)
Other cost of removal obligations		(40,575	)		(41,890	)		(a	)
Fuel-hedging liabilities		(9,642	)		(2,034	)		(f	)
Deferred income tax credits		(7,978	)		(8,738	)		(a	)
Storm damage reserves		(8,737	)		(8,341	)		(e	)
Accelerated cost recovery		—			(1,256	)		(g	)
Property damage reserves		(1,000	)		(1,000	)		(e	)
Injury and damage reserves		66			(123	)		(e	)
Total	$	(35,333	)	$	(28,752	)

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

(a)	Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.
(c)	Amortized over 10 years ending in 2011.
(d)	Transferred to plant in service in the December 2005 fuel cost recovery case. Previously being amortized over 21 months ending in July 2006.
(e)	Recorded and relieved upon the occurrence of a loss.
(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, costs are recovered through the fuel cost recovery clauses.
(g)	Amortized over three-year period ended in May 2005.

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

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report

Revenues

Energy revenues and other revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.

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

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. See Note 3 under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.

Income Taxes

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

Manufacturer’s Tax Credits

The State of Georgia provides a tax credit for qualified investment property to manufacturing companies that construct new facilities. The credit ranges from one percent to five percent of qualified construction expenditures depending upon the county in which the new facility is located. The Company’s policy is to recognize these credits when management believes that they are more likely than not to be allowed by the Georgia Department of Revenue. The amounts recorded for manufacturer’s tax credits were not material for any period presented.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits, and Allowance for Funds Used During Construction (AFUDC).

     The Company’s property, plant, and equipment consisted of the following at December 31:

	2005		2004
	(in thousands)
Generation	$	416,318	$	354,105
Transmission		150,126		148,199
Distribution		411,966		389,074
General		54,846		53,981
Plant in service	$	1,033,256	$	945,359

     The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense. In accordance with Georgia PSC order, the Company is deferring the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizing such costs over 10 years, which approximates the expected maintenance cycle.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.5 percent in 2005, 2.8 percent in 2004, and 2.9 percent in 2003. Depreciation studies are conducted periodically to update the composite rates and are filed with the Georgia PSC. As ordered by the Georgia PSC, the Company lowered its depreciation rates in June 2005. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost — together with the cost of removal, less salvage—is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of certain facilities.

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report

     In the Company’s 2002 rate order, the Georgia PSC ordered the Company to amortize the balance of accelerated cost recovery as a credit to depreciation expense over a three year period beginning June 2002. Accordingly, in 2005, 2004, and 2003, the Company amortized $1.3 million, $3.0 million, and $3.0 million, respectively. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 established new accounting and reporting standards for legal obligations associated with the ultimate costs of retiring long-lived assets. The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. In addition, effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, the Company did not recognize asset retirement obligations for asbestos removal. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected on the balance sheets as a regulatory liability. Therefore, the Company had no cumulative effect to net income resulting from the adoption of Statement No. 143 or Interpretation No. 47.

     The Company has retirement obligations related to various landfill sites, a rail line, and underground storage tanks. As a result of the implementation of Interpretation No. 47, the Company recognized additional asset retirement obligations (and assets) of $3.3 million, primarily related to asbestos removal. The Company has also identified retirement obligations related to certain transmission and distribution facilities. However, liabilities for the removal of these transmission and distribution assets have not been recorded because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated. The Company will continue to recognize in statements of income allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized under Statement No. 143 and Interpretation No. 47 and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Georgia PSC, and are reflected in the balance sheets.

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

	2005			2004
	(in thousands)
Balance beginning of year	$	3,870		$	4,220
Liabilities incurred		3,924			—
Liabilities settled		(602	)		(598	)
Accretion		275			248
Balance end of year	$	7,467		$	3,870

     If Interpretation No. 47 had been adopted as of December 31, 2004, the pro forma asset retirement obligations would have been $7.1 million.

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records AFUDC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The average rates used by the Company to calculate AFUDC were 8.29 percent in 2005, 6.11 percent in 2004, and 4.22 percent in 2003. AFUDC as a percent of net income was 10.0 percent in 2005, 13.5 percent in 2004, and 1.4 percent in 2003.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the

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Savannah Electric and Power Company 2005 Annual Report

impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment provision is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under “Retail Regulatory Matters — Plant McIntosh Construction Project” for information on a regulatory disallowance by the Georgia PSC in December 2004.

Storm Damage Reserve

The Company maintains a storm damage reserve for property damage to cover the cost of uninsured damages from major storms to transmission and distribution facilities and other property. As part of the 2005 retail rate plan approved by the Georgia PSC (2005 Retail Rate Plan), the Company’s annual storm damage accrual was set at $0.3 million.

Environmental Cost Recovery

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company currently recovers environmental costs through its base rates.

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emission allowances. Fuel is charged to inventory when purchased and then expensed as used. Emission allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock on the date of grant. When options are exercised, the Company receives a capital contribution from Southern Company equivalent to the related income tax benefit.

     For pro forma purposes, the Company generally recognizes stock option expense on a straight-line basis over the vesting period. Stock options granted to employees who are eligible for retirement are expensed at the grant date. The pro forma impact on net income of fair-value accounting for options granted is as follows:

	As		Option			Pro
	Reported		Impact			Forma
	(in thousands)
2005	$	29,933	$	(304	)	$	29,629
2004		24,232		(251	)		23,981
2003		23,459		(270	)		23,189

     The estimated fair values of stock options granted in 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted average fair values of stock options:

	2005			2004			2003
Interest rate		3.9	%		3.1	%		2.7	%
Average expected life of stock options (in years)		5.0			5.0			4.3
Expected volatility of common stock		17.9	%		19.6	%		23.6	%
Expected annual dividends on common stock	$	1.43		$	1.40		$	1.37
Weighted average fair value of stock options granted	$	3.90		$	3.29		$	3.59

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Savannah Electric and Power Company 2005 Annual Report

Financial Instruments

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

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

     The Company has implemented a natural gas/oil hedging program as ordered by the Georgia PSC. The program limits the recovery of losses on financial hedging positions through the fuel clause to 10 percent of the Company’s annual natural gas/oil budget. These hedging position limits were $1.1 million for 2003, $2.7 million for 2004, and $5.1 million for 2005 and will be $7.4 million for 2006. The program has operated within the defined hedging position limits set for each year.

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

	Carrying		Fair
	Amount		Value
	(in millions)
Long-term debt:
2005	$	233	$	232
2004	$	233	$	235

     The fair values for long-term debt were based on either closing market prices or closing prices of comparable instruments.

Comprehensive Income

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

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional monthly supplement to certain retirees. No contributions to the plan are expected for the year ending December 31, 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees and directors. Benefits under these non-qualified plans are funded on a cash basis. In addition, the Company has a supplemental retirement plan for certain executive employees. The plan is unfunded and payable from the general funds of the Company. The Company has purchased life insurance on participating executives and plans to use these policies to satisfy this obligation. Due to the merger of the Company with and into Georgia Power, a liability of $0.9 million was accrued for special termination benefits provided by the Company’s supplemental executive retirement plan. See Note 3 under “Retail Regulatory Matters — Merger” for

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Savannah Electric and Power Company 2005 Annual Report

additional information. Also, the Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to the extent required by the Georgia PSC and the FERC. For the year ended December 31, 2006, postretirement trust contributions are expected to total approximately $1.3 million.

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

Pension Plans

The total accumulated benefit obligation for the pension plans was $109.6 million in 2005 and $95.5 million in 2004. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

	Projected
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	103,564		$	94,789
Service cost		2,691			2,478
Interest cost		5,814			5,551
Benefits paid		(4,893	)		(4,575	)
Actuarial loss and employee transfers		8,835			5,162
Amendments		475			159
Contractual termination benefits		898			—
Balance at end of year	$	117,384		$	103,564

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	48,556		$	47,490
Actual return on plan assets		7,040			3,939
Benefits paid		(4,186	)		(4,060	)
Employee transfers		2,239			1,187
Balance at end of year	$	53,649		$	48,556

     In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $104.3 million and $13.1 million, respectively. All plan assets are related to the qualified plan.

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

     Plan assets were invested as follows:

	Plan Assets
	Target			2005			2004
Domestic equity		36	%		40	%		36	%
International equity		24			24			20
Fixed income		15			17			26
Real estate		15			13			10
Private equity		10			6			8
Total		100	%		100	%		100	%

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

	2005			2004
	(in thousands)
Funded status	$	(63,735	)	$	(55,008	)
Unrecognized prior service cost		6,374			6,664
Unrecognized net loss		29,194			26,929
Accrued liability recognized in the balance sheets	$	(28,167	)	$	(21,415	)

     The accrued pension liability is reflected in the balance sheets in the following line items:

	2005			2004
	(in thousands)
Employee benefit obligations	$	(33,768	)	$	(26,601	)
Other property and investments other		1,442			1,634
Accumulated other comprehensive income		4,159			3,552
Accrued liability recognized in the balance sheets	$	(28,167	)	$	(21,415	)

     The amount of accumulated other comprehensive income recognized in the balance sheets relates to the minimum pension liability for non-qualified pension benefit obligations. There is no additional minimum

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Savannah Electric and Power Company 2005 Annual Report

pension liability related to the Company’s tax-qualified pension benefit obligations because they are part of Southern Company’s plan, which is fully funded at December 31, 2005.

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

	2005			2004			2003
	(in thousands)
Service cost	$	2,691		$	2,479		$	2,175
Interest cost		5,814			5,551			5,409
Expected return on plan assets		(3,931	)		(4,047	)		(4,186	)
Recognized net loss		893			532			152
Net amortization		764			753			740
Contractual termination benefits		898			—			—
Net pension cost	$	7,129		$	5,268		$	4,290

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2005, estimated benefit payments were as follows:

	(in thousands)
2006	$	5,293
2007		5,441
2008		5,565
2009		5,851
2010		6,083
2011 to 2015	$	35,296

Postretirement Benefits

Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows:

	Accumulated
	Benefit Obligations
	2005			2004
	(in thousands)
Balance at beginning of year	$	38,965		$	37,249
Service cost		592			546
Interest cost		2,191			2,094
Benefits paid		(1,909	)		(1,459	)
Actuarial loss (gain) and amendments		2,480			535
Balance at end of year	$	42,319		$	38,965

	Plan Assets
	2005			2004
	(in thousands)
Balance at beginning of year	$	13,354		$	11,275
Actual return on plan assets		1,598			1,329
Employer contributions		2,809			2,209
Benefits paid		(1,909	)		(1,459	)
Balance at end of year	$	15,852		$	13,354

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity, as described in the table below. Derivative instruments are used primarily as hedging tools but may also be used to gain efficient exposure to the various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

     Plan assets were invested as follows:

	Plan Assets
	Target			2005			2004
Domestic equity		52	%		52	%		51	%
International equity		11			12			14
Fixed income		30			31			30
Real estate		4			3			3
Private equity		3			2			2
Total		100	%		100	%		100	%

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

	2005			2004
	(in thousands)
Funded status	$	(26,467	)	$	(25,611	)
Unrecognized transition obligation		3,456			3,950
Unamortized prior service cost		1,537			1,651
Unrecognized net loss		12,275			10,986
Fourth quarter contributions		1,485			1,261
Accrued liability recognized in the Balance Sheets	$	(7,714	)	$	(7,763	)

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Savannah Electric and Power Company 2005 Annual Report

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

	2005			2004			2003
				(in thousands)
Service cost	$	592		$	546		$	493
Interest cost		2,191			2,094			2,082
Expected return on plan assets		(881	)		(845	)		(732	)
Recognized net loss		474			205			91
Net amortization		608			756			756
Net postretirement cost	$	2,984		$	2,756		$	2,690

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 and for the year ended December 31, 2005 by approximately $0.2 million and $0.5 million, respectively, and is expected to have a similar impact on future expenses.

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

	Benefit		Subsidy
	Payments		Receipts			Total
			(in thousands)
2006	$	1,996	$	(179	)	$	1,817
2007		2,183		(205	)		1,978
2008		2,379		(229	)		2,150
2009		2,582		(252	)		2,330
2010		2,778		(273	)		2,505
2011 to 2015	$	15,440	$	(1,868	)	$	13,572

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations and the net periodic costs for the pension and postretirement benefit plans were as follows:

	2005			2004			2003
Discount		5.50	%		5.75	%		6.00	%
Annual salary increase		3.00			3.50			3.75
Long-term return on plan assets		8.50			8.50			8.50

     The Company determined the long-term rate of return based on historical asset class returns and current market conditions, taking into account the diversification benefits of investing in multiple asset classes.

     An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 10.25 percent for 2005, decreasing gradually to 4.75 percent through the year 2014, and remaining at that level thereafter.

     An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2005 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in thousands)
Benefit obligation	$	3,273	$	2,382
Service and interest costs		204		180

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee’s base salary. Total matching contributions made to the plan for 2005, 2004, and 2003 were $1.2 million, $1.1 million, and $1.1 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over

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Savannah Electric and Power Company 2005 Annual Report

environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on the Company’s financial statements.

Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added the Company as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities including the Company’s Plant Kraft. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and the Company has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case.

     The Company believes it complied with applicable laws and the EPA’s regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in this matter could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. The Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based

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Savannah Electric and Power Company 2005 Annual Report

rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service area involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not material to the Company’s net income. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between Southern Power and Georgia Power and the Company be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiary, including the Company, will be subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Right of Way Litigation

In late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, the Company, and Southern Telecom, were named as defendants in a lawsuit brought by a telecommunications company that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of an underlying landowner litigation involving Southern Company and certain of its subsidiaries. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this case could result in a substantial judgment; however, the final outcome of this matter cannot now be determined.

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Savannah Electric and Power Company 2005 Annual Report

Retail Regulatory Matters

Merger

On December 13, 2005, Georgia Power and the Company entered into a merger agreement, under which the Company will merge with and into Georgia Power, with Georgia Power continuing as the surviving corporation (the Merger). Pursuant to the Merger agreement, at the effective time of the Merger each share of Georgia Power common stock will remain issued and outstanding; each share of Georgia Power preferred stock currently issued and outstanding will have been redeemed prior to the Merger; the issued and outstanding shares of the Company’s common stock, all of which are held by Southern Company, will be converted into the right to receive 1,500,000 shares of Georgia Power common stock; and each share of the Company’s preferred stock issued and outstanding immediately prior to the Merger will be converted into the right to receive one share of a new series of Georgia Power Class A Preferred Stock. The Merger must be approved by the preferred shareholders of the Company, and is subject to the receipt of certain regulatory approvals from the FERC, the Georgia PSC, and the Federal Communications Commission. Pending regulatory approvals, the Merger is expected to occur by July 2006.

     While the Georgia PSC does not have specific approval authority over the merger of electric utilities, in January 2006, Georgia Power and the Company filed an application with the Georgia PSC for certain approvals necessary to complete the Merger. In particular, Georgia Power and the Company are seeking the approval of the Georgia PSC with respect to the following matters:

• the transfer of the Company’s generating facilities and certification of the generating facilities as Georgia Power assets;

• amendments to Georgia Power’s Integrated Resource Plan to add the current customers and generating facilities of the Company;

• the transfer of the Company’s assigned service territory to Georgia Power;

• adoption of Georgia Power’s service rules and regulations to the current Savannah Electric customers;

• new fuel rate and base rate schedules that would apply to Georgia Power’s sale of electricity to the current company customers; and

• the issuance of additional shares of Georgia Power common stock to Southern Company in exchange for Southern Company’s shares of the Company’s common stock.

Rate Plans

In November 2004, the Company filed a rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in total retail revenues, effective January 1, 2005 to cover the cost of new generation and PPAs, higher operating and maintenance expenses, and continued investment in new transmission and distribution facilities to support growth and ensure reliability. The requested increase was based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent.

     On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for the Company ending May 31, 2008, (2005 Retail Rate Plan). Under the terms of the 2005 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 9.75 percent to 11.75 percent. Two-thirds of any earnings above 11.75 percent will be applied to rate refunds with the remaining one-third retained by the Company. Retail base revenues increased in June 2005 by approximately $9.6 million, or 5.1 percent, on an annual basis. If the Merger is not completed, the Company would be required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued. In connection with the Merger, Georgia Power has requested Georgia PSC approval of a “merger transition charge” that would be used to adjust the Company’s existing base rates to more closely match the existing base rates for Georgia Power. The merger transition charge would remain in effect until the completion of Georgia Power’s next base rate case in 2007 that would be effective on January 1, 2008.

     In May 2002, the Georgia PSC approved a $7.8 million base rate increase and an authorized return on equity of 12 percent as a result of the Company’s request to recover significant new expenses related to the Plant Wansley PPA which began in June 2002, as well as other operation and maintenance expense changes. The Georgia PSC also ordered the Company to amortize approximately $9 million of accelerated depreciation and amortization, previously recorded, equally over three years as a credit to expense beginning June 1, 2002.

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Savannah Electric and Power Company 2005 Annual Report

     In December 2002, at the Company’s request, the Georgia PSC issued an accounting order authorizing the Company to defer until May 2005 approximately $3.8 million annually in Plant Wansley purchased power costs that the Georgia PSC had ruled to be outside the test period for the base rate order. Under the terms of the order, two-thirds of any earnings of the Company in a calendar year above a 12 percent return on common equity were used to amortize the deferred amounts to purchase power expense, with the remainder retained by the Company. The Company also had discretionary authority to amortize up to an additional $1.5 million annually. Through May 31, 2005, the Company had amortized all of the deferred purchased power costs.

Fuel Hedging Program

The Georgia PSC approved a natural gas and oil procurement and hedging program that allows the Company to use financial instruments to hedge price and commodity risk. The order limits the program in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including net losses subject to certain limits, are recovered through the fuel cost recovery clause. Annual net financial gains from the hedging program are shared, with the retail customers receiving 75 percent and the Company retaining 25 percent of the total net gains. Such net gains totaled $10.5 million in 2005, of which the Company has retained $2.6 million.

Fuel Cost Recovery

On August 19, 2005, the Company filed a request with the Georgia PSC for a fuel cost recovery rate increase. On November 10, 2005, the Georgia PSC voted to approve the Company’s request to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $71.8 million as of November 30, 2005 over an estimated four-year period beginning December 1, 2005, as well as future projected fuel costs. Fuel revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the customer fuel rates will have no significant effect on the Company’s net income, but is expected to increase annual cash flow by approximately $52.4 million.

     As a result of recent increases in fuel costs, the Georgia PSC ordered the Company to file a new fuel case on or before January 17, 2006. In connection with the Merger, the Company requested, and the Georgia PSC agreed to postpone the January 2006 filing. Instead, the Company and Georgia Power plan to jointly file a fuel case in March 2006 that would seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined generating fleet. The new fuel cost recovery rate would be paid by all Georgia Power customers, including the existing customers of the Company, following the Merger. Under recovered amounts as of the date of the Merger will be paid by the appropriate customer groups.

     In a separate proceeding on August 2, 2005, the Georgia PSC approved its staff recommendation to initiate an investigation of the Company’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. The Company and Georgia Power are responding to data requests and cooperating in the investigations. The final outcome of this matter cannot now be determined.

Plant McIntosh Construction Project

In December 2002, after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and Georgia Power and the Company for capacity from Plant McIntosh Combined Cycle Units 10 and 11, which was then under construction. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet applicable standards for market-based rates between affiliates. To ensure the timely completion of construction and the availability of the units in the summer of 2005 for their retail customers, the Company and Georgia Power in May 2004 requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities.

     Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs

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Savannah Electric and Power Company 2005 Annual Report

and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. See “FERC Matters — Intercompany Interchange Contract” herein for additional information.

     In December 2004 the Georgia PSC approved the transfer of the Plant McIntosh construction project, at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance, of which approximately $3 million is attributable to the Company and reduced the Company’s 2004 net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost not to exceed $547 million for the project. In June 2005, Plant McIntosh Combined Cycle Units 10 and 11 were placed in service at a total cost that did not exceed the certified amount. In connection with the Company’s 2005 Retail Rate Plan, the Plant McIntosh revenue requirements impact is being reflected in the Company’s rates.

4. JOINT OWNERSHIP AGREEMENTS

The Company operates and jointly owns its Plant McIntosh combustion turbines with Georgia Power. Two of the eight units, totaling 160 megawatts of capacity, are owned by the Company, and six units, totaling 480 megawatts of capacity, are owned by Georgia Power. In addition, the Company and Georgia Power jointly acquired the Plant McIntosh Combined Cycle Units 10 and 11 construction project in 2004. The units, which have a total capacity of 1,319 megawatts, began operation in June 2005. The Company’s amount of investment in the jointly owned Plant McIntosh facilities and related accumulated depreciation at December 31, 2005 were $135 million and $15 million, respectively. The Company’s proportionate share of its combustion turbine and combined cycle plant operating expenses is included in the operating expenses in the statements of income.

5. INCOME TAXES

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

     The transfer of the Plant McIntosh construction project from Southern Power to the Company resulted in a deferred gain to Southern Power for federal income tax purposes. The Company is reimbursing Southern Power for the remaining balance of the deferred tax of $1.0 million as it is reflected in Southern Power’s future taxable income. At December 31, 2005, the payable to Southern Power is included in the Company’s balance sheet under Affiliated Accounts Payable and Other Deferred Credits and totaled $0.3 million and $0.7 million, respectively.

     At December 31, 2005, tax-related regulatory assets and liabilities were $11.5 million and $8.0 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

     Details of income tax provisions are as follows:

	2005			2004		2003
	(in thousands)
Federal —
Currently payable	$	(7,120	)	$	246	$	12,074
Deferred		22,430			12,171		1,299
		15,310			12,417		13,373
State —
Currently payable		(1,683	)		691		2,791
Deferred		3,362			1,270		(646	)
		1,679			1,961		2,145
Total	$	16,989		$	14,378	$	15,518

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Savannah Electric and Power Company 2005 Annual Report

     The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in thousands)
Deferred tax liabilities:
Accelerated depreciation	$	103,991		$	94,124
Property basis differences		(95	)		(845	)
Other		33,301			13,539
Total		137,197			106,818
Deferred tax assets:
Pension and other benefits		22,005			17,353
Other comprehensive income		1,820			1,605
Other		11,979			14,098
Total		35,804			33,056
Total deferred tax liabilities, net		101,393			73,762
Portion included in current assets, net		18,031			16,317
Accumulated deferred income taxes in the Balance Sheets	$	119,424		$	90,079

     In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $0.7 million per year in 2005, 2004, and 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2005			2004			2003
Federal statutory tax rate		35	%		35	%		35	%
State income tax, net of Federal income tax benefit		2			3			4
Other		(3	)		(2	)		1
Effective income tax rate		34	%		36	%		40	%

6. FINANCING

Long-Term Debt and Capital Leases

The Company’s indenture related to its first mortgage bonds is unlimited as to the authorized amount of bonds which may be issued, provided that required property additions, earnings, and other provisions of such indenture are met.

     Assets acquired under capital leases are recorded as utility plant in service, and the related obligation is classified as other long-term debt. Leases are capitalized at the net present value of the future lease payments. At December 31, 2005 and 2004, the Company had capitalized lease obligations for its Plant Kraft coal unloading dock and its vehicles of $5.1 million and $5.8 million, respectively. However, for ratemaking purposes, these obligations are treated as operating leases and, as such, lease payments are charged to expense as incurred. The annual expense incurred for 2005, 2004, and 2003 for the Plant Kraft coal unloading dock was $0.5 million. The annual expense for the vehicles was $0.6 million in 2005, $0.5 million in 2004, and $0.4 million in 2003.

Securities Due Within One Year

At December 31, 2004, the Company was subject to a first mortgage bond improvement (sinking) fund requirement of $200,000, or 1 percent of the outstanding bonds authenticated under the first mortgage bond indenture, other than those issued to collateralize pollution control and other obligations. This requirement was satisfied by pledging additional property equal to 1 2/3 times the requirement.

     The outstanding first mortgage bonds mature in May 2006; therefore, at December 31, 2005, there is no remaining sinking fund requirement. Maturities through 2010 applicable to long-term debt are as follows: $21.0 million in 2006; $1.0 million in 2007; $46.0 million in 2008; $0.8 million in 2009; and $0.5 million in 2010.

Assets Subject to Lien

As amended and supplemented, the Company’s first mortgage bond indenture, which secures the first mortgage bonds issued by the Company, constitutes a direct first lien on substantially all of the Company’s fixed property and franchises.

Bank Credit Arrangements

At the beginning of 2006, credit arrangements with banks totaled $80 million, of which $60 million expires at various times in 2006 and the remaining $20 million expires in 2008. The facilities expiring in 2006 contain two-year term out provisions and the facility that expires in 2008 contains a one-year term out provision.

     In connection with these credit arrangements, the

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NOTES (continued)
Savannah Electric and Power Company 2005 Annual Report

Company agrees to pay commitment fees based on the unused portions of the commitments. Commitment fees are one-eighth of 1 percent or less for the Company.

     The credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the arrangements. Exceeding these debt levels would result in a default under the credit arrangements. In addition, the credit arrangements contain cross default provisions that would be triggered if the Company defaulted on indebtedness over a specified threshold. The cross default provisions are restricted only to indebtedness of the Company. The Company is currently in compliance with all such covenants.

     The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of the Company and the other Southern Company retail operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other retail operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2005, the Company had $49.9 million in commercial paper and $8.9 million in extendible commercial notes outstanding. During 2005, the peak amount of short-term debt outstanding was $63.7 million and the average amount outstanding was $41.9 million. The average annual interest rate on short-term debt was 3.4 percent.

     The Company’s committed credit arrangements provide liquidity support to the Company’s variable rate obligations and to its commercial paper program. At December 31, 2005, the amount of variable rate obligations outstanding requiring liquidity support was $6.7 million.

Financial Instruments

The Company enters into energy related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company has implemented fuel-hedging programs at the direction of the Georgia PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in any period presented.

     At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

	Amounts
	(in thousands)
Regulatory liabilities, net	$	8,752
Other comprehensive income		—
Net income		(4	)
Total fair value	$	8,748

     The fair value gains or losses for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded as regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2008.

     The Company enters into derivatives to hedge exposure to interest rate changes. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives are generally structured to mirror the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.

     At December 31, 2005, the Company had $44 million notional amount of interest rate swaps accounted for as cash flow hedges outstanding with net fair value gains of $0.9 million as follows:

	Weighted Average				Fair
	Fixed				Value
	Rate		Notional		Gain/
Maturity	Paid		Amount		(Loss)
			(in millions)
2007		2.50%*	$	14.0	$	0.3
2016		4.69%	$	30.0	$	0.6

*Swap settles against the Bond Market Association floating rate index.

     The fair value gain or loss for cash flow hedges is recorded in other comprehensive income and is reclassified into earnings at the same time the hedged items affect earnings. For all periods presented, the amounts reclassified from other comprehensive income to interest expense were not material. For 2006, pre-tax

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NOTES (continued)

Savannah Electric and Power Company 2005 Annual Report

gains of approximately $0.1 million are expected to be reclassified from other comprehensive income to interest expense.

Common Stock Dividend Restrictions

The Company’s first mortgage bond indenture contains certain limitations on the payment of cash dividends on common stock. At December 31, 2005, approximately $68 million of retained earnings was restricted against the payment of cash dividends on common stock under the terms of the indenture.

7. COMMITMENTS

Construction Program

The Company is engaged in a continuous construction program, currently estimated to total $44.7 million in 2006, $33.5 million in 2007, and $55.8 million in 2008. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. Construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission, and distribution facilities, including those necessary to meet environmental standards, will continue. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.

Long-Term Service Agreement

The Company and Georgia Power have entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. In summary, the LTSA stipulates that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the contract.

     In general this LTSA is in effect through two major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments by the Company to GE under this agreement are currently estimated at $36 million over the remaining life of the agreement, which may range up to 30 years. However, the LTSA contains various cancellation provisions at the option of the Company and Georgia Power.

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the Company has entered into long-term commitments for the procurement of fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain given volumes with prices based on various indices at the time of delivery. Amounts included in the chart below for natural gas represent estimates based on New York Mercantile Exchange future prices at December 31, 2005.

     Total estimated minimum long-term obligations at December 31, 2005 were as follows:

	Natural
Year	Gas		Coal
	(in thousands)
2006	$	60,829	$	60,615
2007		32,101		11,073
2008		19,187		—
2009		43,943		—
2010		43,943		—
2011 and thereafter		362,804		—
Total commitments	$	562,807	$	71,688

     Additional commitments for fuel will be required to supply the Company’s future needs.

     SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Company Gas. Under these agreements, each of the retail operating companies, Southern Power, and Southern Company Gas may be jointly and severally liable. The creditworthiness of Southern Power and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the

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NOTES (continued)

Savannah Electric and Power Company 2005 Annual Report

Company and each of the retail operating companies to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power or Southern Company Gas as a contracting party under these agreements.

Purchased Power Commitments

The Company has entered into long-term commitments for the purchase of electricity from Southern Power through 2009.

     Estimated total long-term obligations at December 31, 2005 were as follows:

Year	Commitments
	(in thousands)
2006	$	13,240
2007		13,257
2008		13,274
2009		13,286
Total commitments	$	53,057

Operating Leases

The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.9 million for 2005, $0.9 million for 2004, and $0.9 million for 2003. Of these amounts, $0.8 million in each year related to railcar leases and coal dozers and were recoverable through the Company’s fuel cost recovery clause.

     At December 31, 2005, estimated future minimum lease payments for noncancelable operating leases were as follows:

Year	Railcars		Other		Total
	(in thousands)
2006	$	429	$	480	$	909
2007		429		388		817
2008		429		327		756
2009		429		219		648
2010		429		—		429
2011 and thereafter		3,179		—		3,179
Total minimum payments	$	5,324	$	1,414	$	6,738

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2005, 91 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan.
Activity from 2003 to 2005 for the options granted to the Company’s employees under the stock option plan is summarized below.

	Shares			Average
	Subject			Option Price
	To Option			Per Share
Balance at December 31, 2002		550,274		$	20.16
Options granted		125,397			27.98
Options canceled		(8,410	)		25.60
Options exercised		(137,580	)		17.46
Balance at December 31, 2003		529,681			22.62
Options granted		118,209			29.50
Options canceled		(3,708	)		28.21
Options exercised		(90,899	)		18.12
Balance at December 31, 2004		553,283			24.80
Options granted		123,278			32.70
Options canceled		(4,544	)		27.10
Options exercised		(154,033	)		21.85
Balance at December 31, 2005		517,984		$	27.53
Options exercisable:
At December 31, 2003					251,576
At December 31, 2004					318,250
At December 31, 2005					282,133

     The following table summarizes information about options outstanding at December 31, 2005:

	Dollar Price
	Range of Options
	13-21		21-28		28-35
Outstanding:
Shares (in thousands)		58		227		233
Average remaining life (in years)		4.2		6.4		8.6
Average exercise price	$	17.35	$	26.39	$	31.18
Exercisable:
Shares (in thousands)		58		189		35
Average exercise price	$	17.35	$	26.07	$	29.53

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NOTES (continued)

Savannah Electric and Power Company 2005 Annual Report

9. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2005 and 2004 are as follows:

					Net Income
	Operating		Operating		after Preferred
Quarter Ended	Revenues		Income		Stock Dividends
	(in thousands)
March 2005	$	88,588	$	3,944	$	1,020
June 2005		96,588		15,331		7,728
September 2005		150,983		35,146		19,693
December 2005		108,835		6,157		1,492
March 2004	$	72,321	$	8,032	$	2,833
June 2004		91,149		13,971		6,784
September 2004		107,889		24,541		13,416
December 2004		85,601		6,284		1,199

     The Company’s business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005
Savannah Electric and Power Company 2005 Annual Report

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

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SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)
Savannah Electric and Power Company 2005 Annual Report

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

II-332

SOUTHERN POWER COMPANY

FINANCIAL SECTION

II-333

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southern Power Company:

     We have audited the accompanying consolidated balance sheets of Southern Power Company and subsidiaries (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, such consolidated financial statements (pages II-348 to II-361) present fairly, in all material respects, the financial position of Southern Power Company and subsidiaries at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

II-334

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power Company and Subsidiary Companies 2005 Annual Report

OVERVIEW

Business Activities

Southern Power Company and its wholly-owned subsidiaries (the Company) construct, own, and manage the Southern Company’s competitive generation assets and sell electricity at market-based rates in the Super-Southeast wholesale market. The Company focused on executing its regional strategy in 2005 by signing purchased power agreements (PPAs) with investor owned utilities, electric cooperatives, and municipal suppliers for generation assets in the Southeast.

     In June 2005, the Company acquired all of the outstanding general and limited partnership interests of Oleander Power Project, LP (Oleander) from subsidiaries of Constellation Energy Group, Inc. Oleander owns a 628 megawatt (MW) dual-fueled simple cycle combustion turbine plant in Cocoa, Florida, and has PPAs with Florida Power & Light (FPL) and Seminole Electric Cooperative, Inc. (Seminole) covering the entire output of the plant.

     In December 2005, the Company and the Orlando Utilities Commission (OUC) entered into definitive project agreements to develop an integrated coal gasification combined cycle (IGCC) project on OUC’s Stanton Energy Center site in Orlando, Florida. In addition, in February 2006, the Company signed a cooperative agreement with the U.S. Department of Energy (DOE) that provides up to $235 million in funding to be applied by the joint owners for the construction and demonstration of the gasification portion of this project.

     As of December 31, 2005, the Company had 5,403 MWs in commercial operation. The weighted average duration of the Company’s wholesale contracts generally exceeds 10 years, which reduces remarketing risk. However, the Company continues to face challenges at the federal regulatory level relative to market power and affiliate transactions.

Key Performance Indicators

To evaluate operating results and to ensure the Company’s ability to meet its contractual commitments to customers, the Company focuses on several key performance indicators. These indicators consist of plant availability, peak season equivalent forced outage rate (EFOR), and net income. Plant availability shows the percentage of time during the year that the Company’s generating units are available to be called upon to generate (the higher the better), where as the EFOR more narrowly defines the hours during peak demand times when the Company’s generating units are not available due to forced outages (the lower the better). Net income is the primary component of the Company’s contribution to Southern Company’s earnings per share goal. The Company’s actual performance in 2005 surpassed targets in these key performance areas. See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance.

Earnings

The Company’s 2005 earnings were $115 million, a $3 million increase over 2004. The 2005 increase is primarily attributed to the acquisition of Oleander in June 2005 and additional revenues associated with energy margins from fully contracted units, which were partially offset by the expiration of PPAs at Plant Dahlberg. In addition, interest expense increased in connection with the Oleander acquisition as well as the reduction in interest capitalized related to the conclusion of the Company’s initial construction program.

     The Company’s earnings decreased $44 million in 2004 and increased $101 million in 2003. These changes were primarily the result of a one time $50 million gain in May 2003 from the termination of PPAs with Dynegy Inc. (Dynegy). In addition, Plant Stanton A, Plant Franklin Unit 2, and Plant Harris Unit 1 and 2 were all placed into service in 2003 and related revenues from PPAs or opportunity sales began. See Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project” for additional information on the Dynegy transaction.

II-335

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

RESULTS OF OPERATIONS

A condensed income statement is as follows:

						Increase (Decrease)
	Amount						From Prior Year
	2005		2005			2004			2003
			(in thousands)
Operating revenues	$	781,004	$	79,693			$ 19,531		$	383,012
Fuel		209,008		81,905			11,847			17,291
Purchased power		160,056		(28,400	)		3,155			131,638
Other operation and maintenance		80,805		5,610			12,954			33,890
Depreciation and amortization		54,254		3,093			12,149			20,693
Taxes other than income taxes		13,314		2,041			4,608			2,390
Total operating expenses		517,437		64,249			44,713			205,902
Operating income		263,567		15,444			(25,182	)		177,110
Other income, net		2,379		(29	)		4,002			2,988
Less —
Interest expense and other, net		79,322		13,234			34,380			22,822
Income taxes		71,833		(1,102	)		(12,286	)		56,764
Cumulative effect of accounting		—		—			(367	)		367
Net Income	$	114,791	$	3,283			$(43,641	)	$	100,879

Revenues

Operating revenues in 2005 were $781.0 million, a $79.7 million (11.4 percent) increase from 2004. This increase was primarily due to PPAs acquired in the Oleander acquisition, a new PPA with Flint Energies (Flint EMC), and a full year of revenue from PPAs with Georgia Power at Plant Franklin Unit 2 and Plant Harris Unit 2. The Georgia Power PPA for Plant Franklin Unit 2 had a scheduled sales increase in June 2004, while the PPA for Plant Harris Unit 2 became effective June 2004. These increases were partially offset by the expiration of PPAs at Plant Dahlberg. See FUTURE EARNING POTENTIAL – “Power Sales Agreements” and Note 2 to the financial statements under “Oleander Acquisition” for additional information.

     Operating revenues in 2004 were $701.3 million, a $19.5 million (2.9 percent) increase from 2003. The increase was primarily related to a full year of revenues under PPAs from new units. Plant Harris Units 1 and 2 and Plant Franklin Unit 2 were placed in service in June 2003. Plant Stanton A was placed in service in October 2003.

     Operating revenues in 2003 were $681.8 million, a $383.0 million (128.2 percent) increase from 2002. In 2003, operating revenues increased due to a one time gain from a termination settlement with Dynegy and new PPAs or opportunity sales from four new units placed into service. Also contributing to this increase was a $9.9 million dollar increase in service and fee revenues from various electric membership cooperative (EMC) contracts.

     Capacity revenues are an integral component of the Company’s PPAs with both affiliate and non-affiliate customers and represent the greatest contribution to net income. Energy under PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Details of these PPA capacity and energy revenues are as follows:

	2005		2004		2003
			(thousands)
Capacity revenues
Affiliates	$	278,221	$	247,914	$	163,341
Non-Affiliates		68,645		73,980		54,064
Total		346,866		321,894		217,405
Energy revenues
Affiliates		254,844		124,837		103,340
Non-Affiliates		141,496		80,825		55,906
Total		396,340		205,662		159,246
Total PPA revenues	$	743,206	$	527,556	$	376,651

     Revenues from sales to affiliated and non-affiliated companies that are not covered by PPAs are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the Federal Energy Regulatory Commission (FERC), and will vary depending on demand and the availability and cost of generating resources at each company that participates in the centralized operation and dispatch of the Southern Company fleet of generating plants (Southern Pool). These transactions do not have a significant impact on earnings since the energy is generally sold at variable cost.

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Expenses

Fuel and Purchased Power

In 2005, fuel expense increased by $81.9 million or 64.4 percent. The increase was driven by a 54.2 percent increase in the average cost of natural gas per decatherm. In 2004, fuel expense increased by $11.8 million or 10.3 percent primarily due to increased gas transportation expenses associated with Plant Harris Unit 2 prior to its commitment with Georgia Power. The average cost of natural gas per decatherm also increased 8.3 percent from 2003 to 2004. In 2003, fuel expense increased $17.3 million or 17.7 percent primarily due to the operation of Plant Wansley Units 6 and 7 for a full year, as well as the commencement of commercial operations of Plant Franklin Unit 2 and Plant Harris Units 1 and 2 in June 2003. Opportunity sales made from Plant Franklin Unit 2 and Plant Harris Unit 2 prior to their commitment under affiliate PPAs also contributed to the increase in fuel expense. The average cost of natural gas per decatherm increased 24 percent from 2002 to 2003.

     A significant upward trend in the cost of natural gas has emerged since 2003, and volatility in this market is expected to continue. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2005 and 2004 hurricanes result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses incurred under the Company’s PPAs are generally the responsibility of the counterparties and do not significantly affect net income. Under the PPAs, either the Company incurs the fuel expense and concurrently recovers the cost through energy revenues or the counterparty purchases the fuel directly.

     Purchased power decreased $28.4 million in 2005, primarily due to increased PPA commitments for the Company’s generating resources beginning in June 2004. Previously, capacity from some of these units was sold into the short-term market and related energy sales were sometimes served with short-term power purchases from both affiliates and non-affiliates when market costs were lower than the cost of self-generation.

     Purchased power increased $3.2 million in 2004 over 2003, consisting of a $15.4 million increase for non-affiliates and a $12.3 million decrease for affiliates as a result of the availability of lower cost energy from contracts with Georgia EMCs and North Carolina municipalities, in addition to other market sources. Purchased power increased by $131.6 million in 2003 as a result of the availability of lower cost generating capacity primarily due to the mild summer weather in Southern Company’s retail service territory.

     The amount of purchased power expenses between affiliates and non-affiliates will vary depending on demand and the availability and cost of generating resources available throughout the Southern Company electric system. Load requirements are submitted to the Southern Pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by the Company, affiliate-owned generation, or external purchases.

Operations and Maintenance

Other operations and maintenance, depreciation and amortization expenses, and taxes other than income taxes all increased during the period from 2002 through 2005. These year-to-year increases are primarily the result of new generating units. In 2002, Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 were placed into service. Four more units were placed in service in 2003 including Plant Franklin Unit 2, Plant Harris Units 1 and 2, and Plant Stanton A. Plant Oleander was acquired in June 2005.

Interest Expense

Interest expense has increased by $13.2 million, $34.4 million, and $22.8 million in 2005, 2004, and 2003, respectively. These increases were primarily the result of additional debt incurred for the Oleander acquisition, and a lower percentage of interest costs being capitalized as projects reached completion, were sold, or were suspended. Plant McIntosh Units 10 and 11 were transferred to Georgia Power and Savannah Electric and construction was suspended on Plant Franklin Unit 3 during 2004, effectively ceasing all capitalized interest. For additional information, see FUTURE EARNINGS POTENTIAL — “Construction Projects – Plant Franklin Unit 3” and Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project.”

Other Income and Expense

The increases in other income net, in 2004 and 2003 were primarily the result of realized gains and losses on derivative energy contracts. See FINANCIAL

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CONDITION AND LIQUIDITY – “Market Price Risk” herein and Notes 1 and 5 to the financial statements under “Financial Instruments.”

Effects of Inflation

The Company is party to long-term contracts that are generally based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in generating facilities with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt.

FUTURE EARNINGS POTENTIAL

General

The results of operations for the past three years are not necessarily indicative of future earnings potential. Several factors affect the opportunities, challenges, and risks of the Company’s competitive wholesale energy business. These factors include the ability to achieve sales growth while containing costs. Another major factor is federal regulatory policy, which may impact the Company’s level of participation in this market. The level of future earnings depends on numerous factors including regulatory matters such as those related to affiliate contracts, sales, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire.

Power Sales Agreements

The Company’s sales are primarily through long-term PPAs. The Company is working to maintain and expand its share of the wholesale market in the Southeastern power markets. Although there is currently an oversupply of generating capacity in the Super Southeast, opportunities remain in certain areas.

     In February 2006, the Company entered into a PPA with Florida Municipal Power Agency (FMPA) to commence in 2007 and extend through 2022. The Company will provide FMPA with the output from a dedicated unit to be constructed at the Plant Oleander site.

     In June 2005 as part of the Oleander acquisition, the Company acquired PPAs with FPL and Seminole. The FPL PPA is for one unit and extends through the end of May 2007. The Seminole PPA is for the three remaining units at Plant Oleander and extends through the end of 2009. In February 2006, the Company signed an extension of the FPL PPA for approximately 160 MWs of capacity through May 2012. Also in February 2006, the Company signed a new PPA with Seminole for approximately 320 MWs of capacity through December 2015. See Note 2 to the financial statements under “Oleander Acquisition” for additional information.

     In August 2004, the Company entered into two PPAs with FPL. Under the PPAs, the Company will provide FPL with a total of 790 MWs of capacity annually from Plant Harris Unit 1 and Plant Franklin Unit 1 for the period from June 2010 through December 2015. A similar PPA with Progress Energy Florida (Progress) was signed in November 2004 for 350 MWs from Franklin Unit 1 for the period June 2010 through December 2015. The Florida Public Service Commission has approved these contracts.

     Also in 2004, the Company executed multiple agreements expanding its relationship with existing customers. For the years 2005 through 2009, the Company will sell approximately 130 MWs of additional wholesale capacity from existing resources to Flint EMC. The Company also agreed to a 10-year extension of the OUC PPA for Stanton Unit A.

     In June 2003, the Company placed Plant Franklin Unit 2 and Plant Harris Units 1 and 2 into commercial operation. In October 2003, the Company placed Plant Stanton A into commercial operation. In June 2004, sales under PPAs with Georgia Power for the remaining 200 MWs of uncontracted capacity at Plant Franklin Unit 2 and for Plant Harris Unit 2 began. Sales under PPAs for the other units became effective upon commercial operation.

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     The Company has entered into long-term power sales agreements for a portion of its generating capacity as follows:

	Capacity		Initial
Project	(megawatts)		Term (1)
Affiliated
Franklin Unit 1		563		6/02-5/10
Franklin Unit 2		623		6/03-5/11
Wansley Units 6 & 7		1,129		6/02-12/09
Harris Unit 1		625		6/03-5/10
Harris Unit 2		628		6/04-5/19
Non-Affiliated
Stanton A (OUC)		338		11/03-10/23
Stanton A (KUA, FMPA)		85		11/03-10/13
GA EMC Full Requirements (2)		62-434		2002-2009
Oleander (FPL)		160		6/05-5/12
Oleander (Seminole)		533		6/05-12/09
Oleander (Seminole)		320		1/10-12/15
Oleander (FMPA)		160		12/07-12/22
Piedmont (PMPA) Full Requirements		135-181		2006-2010
Franklin Unit 1 (FPL/Progress)		540		6/10-12/15
Harris Unit 1 (FPL)		625		6/10-12/15

(1)	Excluding automatic renewal provisions
(2)	Option in 2009 to convert from full requirements to fixed capacity sale.

     Although some of the Company’s PPAs are with Southern Company’s five retail operating companies, the Company’s generating facilities are not in the retail operating companies’ regulated rate bases, and the Company is not able to seek recovery from their ratepayers for construction, repair, environmental, or maintenance costs. The Company expects that the capacity payments in the PPAs will produce sufficient cash flow to meet these costs, pay debt service, and provide an equity return. However, the Company’s overall profit will depend on numerous factors, including efficient operation of its generating facilities.

     As a general matter, existing PPAs provide that the purchasers are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, the Company may be responsible for excess fuel costs. With respect to fuel transportation risk, most of the Company’s PPAs provide that the counterparties are responsible for procuring and transporting the fuel to the particular generating facility.

     Fixed and variable operation and maintenance costs will be recovered through capacity charges based on dollars-per-kilowatt year or dollars-per-megawatt hour. The Company has long-term service contracts with General Electric (GE) to reduce its exposure to certain operation and maintenance costs relating to GE equipment. See Note 6 to the financial statements under “Long-Term Service Agreements” for additional information.

     The Company’s PPAs with non-affiliated counterparties have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard & Poor’s or Moody’s downgrades the credit ratings of such counterparty to below investment grade or the counterparty is not rated or fails to maintain a minimum coverage ratio. The PPAs are expected to provide the Company with a stable source of revenue during their respective terms.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices and to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15-months. In the event that the FERC’s default mitigation measures for entities that are found

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Southern Power Company and Subsidiary Companies 2005 Annual Report

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

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, the Company, and Southern Company Services, Inc. (SCS), as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of the Company as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving the approval of PPAs between the Company and Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, are subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Environmental Matters

The Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Such statutes and regulations include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also affect the Company.

     New environmental legislation or regulations, or changes to existing statutes or regulations could affect many areas of the Company’s operations. While the Company’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

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     Because each of the Company’s units are newer gas-fired generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal-fired generating facilities or older gas-fired generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise, and concerns about potential adverse health impacts, can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statutes and regulations on the Company as a result of generating facilities that may be acquired or constructed in the future cannot be predicted at this time.

     Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements such as opacity and other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such potential litigation against the Company cannot be predicted at this time.

Construction Projects

Integrated Gasification Combined Cycle (IGCC)

In December 2005, the Company and OUC executed definitive agreements for development of the IGCC, a project of approximately 285 MW in Orlando, Florida, adjacent to Plant Stanton Unit A, which is co-owned by the Company, OUC and others. The definitive agreements provide that the Company will own at least 65 percent of the gasifier portion of the project. OUC will own the remainder of the gasifier portion and 100 percent of the combined cycle portion of the project. OUC will make capacity payments for all of the Company’s gasifier capacity once the plant is in commercial operation. The Company will construct the project and bill OUC a fixed price for its share in the project. The Company will also manage operations after construction is completed using a joint staff of OUC and SCS employees.

     A cooperative agreement with DOE was signed in February 2006, which provides for up to $235 million in funding from the DOE to be applied by the joint owners for the construction and demonstration of the gasification portion of the project. The DOE will provide the funding in four phases throughout the development and demonstration of the gasifier. The Company’s share of the total cost related to the gasifier portion of the project is currently estimated at approximately $121 million. The IGCC project, subject to National Environmental Policy Act review and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in 2010.

Plant Franklin Unit 3

In August 2004, the Company completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project and suspended further construction. Final completion is not anticipated until the 2008-2011 period. See Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project” for more information. The final outcome of this matter cannot now be determined.

Other Matters

The Company is currently conducting a depreciation study to update the composite depreciation rates for its property, plant, and equipment. The impact of this possible change cannot be determined at this time.

     From time to time, the Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. See Note 2 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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Southern Power Company and Subsidiary Companies 2005 Annual Report

Revenue Recognition

The Company’s revenue recognition depends on appropriate classification and documentation of transactions in accordance with Financial Accounting Standards Board (FASB) Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. In general, the Company’s power sale transactions can be classified in one of four categories: non-derivatives, normal sales, cash flow hedges, and mark to market. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” herein and Notes 1 and 5 to the financial statements under “Financial Instruments.” The Company’s revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. Factors that must be considered in making these determinations include:

• Assessing whether a sales contract meets the definition of a lease

• Assessing whether a sales contract meets the definition of a derivative

• Assessing whether a sales contract meets the definition of a capacity contract

• Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery

• Ensuring that the contract quantities do not exceed available generating capacity

• Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged

• Assessing hedge effectiveness at inception and throughout the contract term.

Normal Sale and Non-Derivative Transactions

The Company considers derivative contracts, including capacity contracts, which provide for the sale of electricity to be physically delivered in quantities within the Company’s available generating capacity to be normal sales. In accordance with FASB Statement No. 133, such transactions are accounted for as executory contracts and are not subject to mark to market accounting. Therefore, the related revenue is recognized, in accordance with Emerging Issues Task Force (EITF) No. 91-6, Revenue Recognition of Long-Term Power Sales Contracts, on an accrual basis in amounts equal to the lesser of the levelized amount or the amount billable under the contract, over the respective contract periods. Revenues from transactions that do not meet the definition of a derivative are also recorded in this manner. Contracts recorded on the accrual basis represented the majority of the Company’s operating revenues for the year ended December 31, 2005.

Cash Flow Hedge Transactions

The Company designates other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions. These contracts are marked to market through Other Comprehensive Income over the life of the contract. Realized gains and losses are then recognized in revenues as incurred.

Mark to Market Transactions

Contracts for sales of electricity that are not normal sales and are not designated as cash flow hedges are marked to market and recorded directly through net income. Net unrealized gains on such contracts were not material for the year ended December 31, 2005.

Asset Impairments

The Company’s investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company evaluates the carrying value of these assets under FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, whenever indicators of potential impairment exist. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses, or a projection of continuing losses or a significant decrease in market prices. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:

• Future demand for electricity based on projections of economic growth and estimates of available generating capacity

• Future power and natural gas prices, which have been quite volatile in recent years

• Future operating costs.

     To date, the Company’s evaluations of its assets have not required any impairment to be recorded. See Note 2 to

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the financial statements under “Plant Franklin Unit 3 Construction Project” for additional information.

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1), which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

Conditional Asset Retirement Obligations

Effective December 31, 2005, the Company adopted the provisions of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” The adoption of FIN 47 had no impact on the Company’s financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The major change in the Company’s financial condition during 2005 was the June acquisition of Oleander, which contributed $218 million of utility plant and working capital. See Note 2 to the financial statements under “Oleander Acquisition” for additional information. The Company has received investment grade ratings from the major rating agencies.

Sources of Capital

The Company may use operating cash flows, external funds, or equity capital from Southern Company to finance any new projects, acquisitions and ongoing capital requirements. The Company expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks.

     The Company’s current liabilities frequently exceed current assets due to the use of short-term debt as a funding source. At December 31, 2005, the Company had approximately $27.6 million of cash and cash equivalents to meet short-term cash needs and contingencies. To meet liquidity and capital resource requirements, the Company had at December 31, 2005, $399 million of unused committed credit arrangements with banks. Subject to certain financial covenants, these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for the Company’s commercial paper program. See Note 5 to the financial statements under “Bank Credit Arrangements” for additional information.

     The Company’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At December 31, 2005, there was $110.7 million of commercial paper outstanding. See Note 5 to the financial statements under “Commercial Paper” for additional information.

     The issuance of all securities by the Company is generally subject to regulatory approval by the FERC. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets. Additionally, with respect to the public offering of securities, the Company will be required to file registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating change to BBB- or Baa3, or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2005 the maximum potential collateral requirements at BBB- or Baa3 were approximately $190 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $357 million. Generally, collateral may be provided with a Southern Company guaranty, letter of credit, or cash. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2005, the

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Company had no material exposure related to these agreements.

     Subsequent to December 31, 2005, the Company has entered into additional physical electricity purchases and sales contracts adding $9 million to the maximum potential collateral requirements at a credit rating of BBB and Baa2 and $17 million at BBB- or Baa3 and below.

Market Price Risk

The Company is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, the Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and hedging practices. Company policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.

     Because energy from the Company’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company’s exposure to market volatility in commodity fuel prices and prices of electricity is limited. To mitigate residual risks in those areas, the Company enters into fixed-price contracts for the sale of electricity.

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

	Changes in Fair
	Value
	2005			2004
	(in thousands)
Contracts beginning of year	$	9		$	665
Contracts realized or settled		(168	)		(469	)
New contracts at inception		—			—
Current period changes (a)		382			(187	)
Contracts end of year	$	223		$	9

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

     At December 31, 2005, the sources of the valuation prices were as follows:

	Source of 2005 Year-End Valuation Prices
	Total			Maturity
	Fair Value			2006			2007-2008
				(in thousands)
Actively quoted	$	259		$	217		$	42
External sources		(36	)		(36	)		—
Models and other methods		—			—			—
Contracts end of year	$	223		$	181		$	42

     Unrealized pre-tax gains and losses on electric contracts used to hedge anticipated sales, and gas contracts used to hedge anticipated purchases and sales, are deferred in Other Comprehensive Income. Gains and losses on contracts that do not represent hedges are recognized in the income statement as incurred.

     At December 31, 2005, the fair value of derivative energy contracts was as follows:

	Amounts (in thousands)
Net Income	$	153
Other Comprehensive Income		70
Total fair value	$	223

     Approximately, $0.1 million, $0.3 million, and $(1.9) million of unrealized pre-tax gains (losses) were recognized in income in 2005, 2004, and 2003, respectively. The Company is exposed to market-price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Standard & Poor’s and Moody’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 5 to the financial statements under “Financial Instruments.”

     At December 31, 2005, the Company had no variable long-term debt outstanding. Therefore, there would be no effect on annualized interest expense related to long-term debt if the Company sustained a 100 basis point change in interest rates. The Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

Capital Requirements and Contractual Obligations

The capital program of the Company is currently estimated to be $162.3 million for 2006, $265.2 million for 2007, and $221.0 million for 2008. These amounts include estimates for potential plant acquisitions and/or new construction. Currently, there are no plants under construction. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital.

     Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, and other purchase commitments are as follows. See Notes 1, 5, and 6 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (Continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

			2007-		2009-		After
Contractual Obligations	2006		2008		2010		2010		Total
	(in millions)
Long-term debt(a) —
Principal	$	0.2	$	1.3	$	—	$	1,100.0	$	1,101.5
Interest		61.6		123.1		123.1		199.8		507.6
Operating leases		0.7		0.9		0.6		25.1		27.3
Purchase commitments(b)—
Capital(c)		162.3		486.2		—		—		648.5
Natural gas(d)		20.9		42.0		45.7		300.1		408.7
Long-term service agreements		27.4		83.0		76.2		938.5		1,125.1
Total	$	273.1	$	736.5	$	245.6	$	2,563.5	$	3,818.7

(a) All amounts are reflected based on final maturity dates. The Company plans to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

(b) The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for the last three years were $80.8 million, $75.2 million, and $62.2 million, respectively.

(c) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures.

(d) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on New York Mercantile Exchange future prices at December 31, 2005.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (Continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, earnings growth, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

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

• available sources and costs of fuels;

• ability to control costs;

• advances in technology;

• the ability to avoid cost overruns during the development and construction of facilities, including the IGCC;

• state and federal rate regulations;

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

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

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

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

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

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

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

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

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

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

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

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

II-347

CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Revenues:
Sales for resale —
Non-affiliates	$	223,058		$	266,463		$	278,559
Affiliates		556,664			425,065			312,586
Contract termination		—			—			80,000
Other revenues		1,282			9,783			10,635
Total operating revenues		781,004			701,311			681,780
Operating Expenses:
Fuel		209,008			127,103			115,256
Purchased power —
Non-affiliates		57,182			76,652			61,234
Affiliates		102,874			111,804			124,067
Other operations		61,235			58,111			50,852
Maintenance		19,570			17,084			11,389
Depreciation and amortization		54,254			51,161			39,012
Taxes other than income taxes		13,314			11,273			6,665
Total operating expenses		517,437			453,188			408,475
Operating Income		263,567			248,123			273,305
Other Income and (Expense):
Interest expense, net of amounts capitalized		(79,322	)		(66,088	)		(31,708	)
Other income (expense), net		2,379			2,408			(1,594	)
Total other income and (expense)		(76,943	)		(63,680	)		(33,302	)
Earnings Before Income Taxes		186,624			184,443			240,003
Income taxes		71,833			72,935			85,221
Earnings Before Cumulative Effect of Accounting Change		114,791			111,508			154,782
Cumulative effect of accounting change— less income taxes of $231		—			—			367
Net Income	$	114,791		$	111,508		$	155,149

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

II-348

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report

	2005			2004			2003
	(in thousands)
Operating Activities:
Net income	$	114,791		$	111,508		$	155,149
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		68,210			65,838			47,267
Deferred income taxes and investment tax credits, net		24,055			23,510			22,521
Deferred revenues		(370	)		10,064			9,997
Tax benefit of stock options		686			415			130
Hedge settlements		—			—			(93,298	)
Other, net		2,777			9,957			(25,787	)
Changes in certain current assets and liabilities —
Receivables		(42,355	)		(14,009	)		(7,008	)
Fossil fuel stock		(4,316	)		2,894			5,232
Materials and supplies		(4,096	)		(1,715	)		(1,570	)
Other current assets		(5,900	)		4,144			(9,675	)
Accounts payable		41,662			(13,844	)		32,694
Accrued taxes		5,782			32,330			(6,939	)
Accrued interest		535			(1,386	)		9,299
Other current liabilities		—			(306	)		236
Net cash provided from operating activities		201,461			229,400			138,248
Investing Activities:
Property additions		(241,103	)		(115,606	)		(344,362	)
Sale of property to affiliates		—			414,582			—
Change in construction payables, net		(124	)		(14,349	)		(16,931	)
Other		—			(10,043	)		—
Net cash provided from (used for) investing activities		(241,227	)		274,584			(361,293	)
Financing Activities:
Increase (decrease) in notes payable, net — affiliated		—			—			(20,488	)
Increase (decrease) in notes payable, net		110,692			(114,349	)		114,347
Proceeds —
Senior notes		—			—			575,000
Capital contributions from parent company		5,022			2,808			5,952
Redemptions —
Senior notes		—			(50,000	)		—
Other long-term debt		(200	)		—			(379,640	)
Capital distributions to parent company		—			(113,000	)		(77,000	)
Payment of common stock dividends		(72,400	)		(207,000	)		—
Other		(958	)		—			(11,802	)
Net cash provided from (used for) financing activities		42,156			(481,541	)		206,369
Net Change in Cash and Cash Equivalents		2,390			22,443			(16,676	)
Cash and Cash Equivalents at Beginning of Year		25,241			2,798			19,474
Cash and Cash Equivalents at End of Year	$	27,631		$	25,241		$	2,798
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $0, $17,368 and $36,736 capitalized, respectively)	$	64,487		$	52,146		$	105,765
Income taxes (net of refunds)		33,751			13,313			77,993

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

II-349

CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Power Company and Subsidiary Companies 2005 Annual Report

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

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

II-350

CONSOLIDATED BALANCE SHEETS
At December 31, 2005 and 2004
Southern Power Company and Subsidiary Companies 2005 Annual Report

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

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

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report

									Other
	Common		Paid-In			Retained			Comprehensive
	Stock		Capital			Earnings			Income (loss)			Total
	(in thousands)
Balance at December 31, 2002	$	—	$	731,230		$	62,477		$	(47,103	)	$	746,604
Net income		—		—			155,149			—			155,149
Conversion of parent company debt to equity		—		190,000			—			—			190,000
Capital distributions to parent company		—		(77,000	)		—			—			(77,000	)
Capital contributions from parent company		—		6,082			—			—			6,082
Other comprehensive income (loss)		—		—			—			(9,359	)		(9,359	)
Balance at December 31, 2003		—		850,312			217,626			(56,462	)		1,011,476
Net income		—		—			111,508			—			111,508
Capital distributions to parent company		—		(113,000	)		—			—			(113,000	)
Capital contributions from parent company		—		3,223			—			—			3,223
Other comprehensive income (loss)		—		—			—			5,404			5,404
Cash dividends on common stock		—		—			(207,000	)		—			(207,000	)
Balance at December 31, 2004		—		740,535			122,134			(51,058	)		811,611
Net income		—		—			114,791			—			114,791
Capital contributions from parent company		—		5,708			—			—			5,708
Other comprehensive income (loss)		—		—			—			6,633			6,633
Cash dividends on common stock		—		—			(72,400	)		—			(72,400	)
Balance at December 31, 2005	$	—	$	746,243		$	164,525		$	(44,425	)	$	866,343

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2005, 2004, and 2003
Southern Power Company and Subsidiary Companies 2005 Annual Report

	2005		2004			2003
	(in thousands)
Net income	$	114,791	$	111,508		$	155,149
Other comprehensive income (loss):
Changes in fair value of qualifying hedges, net of tax of $106, $(520), and $(7,872), respectively		164		(920	)		(12,788	)
Less: Reclassification adjustment for amounts included in net income, net of tax of $4,155, $3,964 and $1,868, respectively		6,469		6,324			3,429
Total other comprehensive income (loss)		6,633		5,404			(9,359	)
Comprehensive Income	$	121,424	$	116,912		$	145,790

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

II-352

NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2005 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Southern Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is also the parent company of five retail operating companies, Southern Company Services (SCS), Southern Communications Services (SouthernLINC Wireless), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Telecom and other direct and indirect subsidiaries. The retail operating companies — Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company — provide electric service in four Southeastern states. The Company constructs, owns and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market. Contracts among the retail operating companies and the Company — related to jointly owned generating facilities, interconnecting transmission lines or the exchange of electric power — are regulated by the Federal Energy Regulatory Commission (FERC). SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast. Southern Telecom provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and energy related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants. On January 4, 2006, Southern Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural gas marketing subsidiary.

     Southern Company was registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on February 8, 2006, and Southern Company and its subsidiaries, including the Company, were subject to the regulatory provisions of the PUHCA. The Company is subject to regulation by the FERC. The Company follows accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates.

     The financial statements include the accounts of the Company and its wholly-owned subsidiaries, Southern Company — Florida LLC (SCF), Oleander Power Project LP (Oleander) and Southern Power Company — Orlando Gasification LLC (SPC-OG), which were established to own, operate, and maintain the Company’s ownership interests in Plant Stanton Unit A, Oleander, and the integrated gasification combined cycle (IGCC) plant, respectively. See Note 2 under “Oleander Acquisition” and Note 3 for further information. All intercompany accounts and transactions have been eliminated in consolidation.

Affiliate Transactions

The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, purchasing, accounting and statistical analysis, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures and other services with respect to business and operations and power pool transactions. SCS also enters into fuel purchase and transportation arrangements and contracts, financial instruments for purposes of hedging and wholesale energy purchase and sale transactions for the benefit of the Company. Because the Company has no employees, all employee related charges are rendered at cost under agreements with SCS or the retail operating companies. Costs for these services from SCS amounted to approximately $51.9 million in 2005, $46.7 million in 2004, and $47.5 million in 2003. Approximately $47.8 million in 2005, $40.3 million in 2004, and $32.8 million in 2003, were general, administrative, operation and maintenance expenses; the remainder was capitalized to construction work in progress. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of PUHCA and management believes they are reasonable.

     The Company has agreements with Georgia Power and Alabama Power to provide operations and maintenance services for Plants Dahlberg, Wansley, Franklin, and Harris. These services are billed at cost on a monthly basis and are recorded as operations and maintenance expense in the accompanying statements of

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NOTES(continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

income. For the periods ended December 31, 2005, 2004, and 2003, these services totaled approximately $7.1 million, $6.6 million, and $6.1 million, respectively.

     Total billings for all purchased power agreements (PPAs) in effect with affiliates totaled $531 million, $383.0 million, and $282.2 million in 2005, 2004 and 2003 respectively. Included in these billings were $37.5 million, $39.1 million, and $28.4 million of affiliated deferred capacity revenues recorded on the balance sheets at December 31, 2005, December 31, 2004, and December 31, 2003, respectively.

     The Company and the retail operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements.

     The Company and the retail operating company affiliates generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.

Revenues

Capacity is sold at rates specified under contractual terms and is recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. Energy is generally sold at market-based rates and the associated revenue is recognized as the energy is delivered. See “Financial Instruments” herein for additional information.

     Significant portions of the Company’s revenues have been derived from certain customers. For the year ended December 31, 2005, Georgia Power accounted for 53.6 percent of revenues, while Alabama Power and Savannah Electric were 8.2 percent and 6.5 percent of revenues, respectively. For the year ended December 31, 2004, Georgia Power accounted for 40.3 percent of revenues, with Alabama Power and Savannah Electric accounting for 8.4 percent and 4.5 percent of revenues, respectively. For the year ended December 31, 2003, Georgia Power accounted for approximately 33.7 percent of revenues, excluding $80 million related to termination of contracts with Dynegy, Inc. (Dynegy), with Alabama Power and Savannah Electric accounting for 5.5 percent and 5.0 percent, respectively.

Fuel Costs

Fuel costs are expensed as the fuel is consumed.

Income Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.

Property, Plant, and Equipment

The Company’s property, plant, and equipment consist entirely of generation assets.

     Property, plant, and equipment is stated at original cost. Original cost includes materials, direct labor incurred by affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred.

Manufacturer’s Tax Credits

The State of Georgia provides a tax credit for qualified investment property to manufacturing companies that construct new facilities. The credit ranges from 1 percent to 5 percent of construction expenditures depending upon the county in which the new facility is located. The Company’s policy is to recognize these credits when management believes they are more likely than not to be allowed by the Georgia Department of Revenue. Manufacturer’s tax credits of $11.8 million were recorded in 2003. There were no credits recorded in 2004 or 2005.

Depreciation

Depreciation of the original cost of assets is computed under the straight-line method based on the assets’ estimated useful lives determined by the Company. The primary assets in property, plant and equipment are power plants, all of which have an estimated useful life of 35 years, except Plant Dahlberg and Plant Oleander which have an estimated useful life of 40 years. These lives reflect a composite of the significant components (called retirement units) that make up the plants. Depreciation studies are conducted periodically to update the composite

II-354

NOTES(continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

rates. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized.

Asset Retirement Obligations and Other Costs of Removal

The present value of the ultimate costs for an asset’s future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life.

     At December 31, 2005, the Company had no liability for asset retirement obligations. In connection with the adoption of Financial Accounting Standards Board Statement No. 143, Accounting for Asset Retirement Obligations, in January 2003, the Company recorded a reduction to the accumulated reserve for depreciation and a cumulative effect of change in accounting principle of $0.6 million ($0.4 million after-tax), representing removal costs for long-lived assets that the Company did not have a legal obligation to retire.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment loss recognized is determined by estimating the fair value of the assets and recording a loss for the amount of the carrying value that is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Deferred Project Development Costs

The Company capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a power plant constructed. These costs include professional services, permits and other costs directly related to the construction of a new project. These costs are generally transferred to construction work in progress upon commencement of construction. The total deferred project development costs were $3.8 million at December 31, 2005 and $3.2 million at December 31, 2004.

Cash and Cash Equivalents

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

Materials and Supplies

Generally, materials and supplies include generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Materials and supplies are recorded at average cost.

Fuel Inventory

Fuel inventory includes the average cost of oil and emission allowances. The Company maintains minimal oil levels for use at Plant Dahlberg and Plant Oleander. Inventory is maintained using the weighted average cost method. Fuel and emissions are charged to inventory when purchased and then expensed as used.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in Other Comprehensive Income

II-355

NOTES(continued)
Southern Power Company and Subsidiary Companies 2005 Annual Report

until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income.

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

     The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:

	Carrying		Fair
	Amount		Value
	(in millions)
Long-term debt:
2005	$	1,100	$	1,117
2004	$	1,099	$	1,114

     The fair values for securities were based on either closing market prices or closing prices of comparable instruments.

Comprehensive Income

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

2. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

From time to time, the Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements such as opacity or other air quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such potential litigation against the Company cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising would have a material adverse effect on the Company’s financial statements.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices and to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

     In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded

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Southern Power Company and Subsidiary Companies 2005 Annual Report

investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory involving any Southern Company subsidiary, including the Company, are subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is expected to be immaterial to the Company. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the propriety of the continued inclusion of the Company as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining the Company as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of the Company, the FERC authorized the Company’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a proceeding involving approval of PPAs between the Company, Georgia Power, and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries, including the Company, will be subject to refund to the extent the FERC orders any changes to the IIC.

     The Company believes that there is no meritorious basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Oleander Acquisition

On June 7, 2005, the Company acquired all of the outstanding general and limited partnership interests of Oleander from subsidiaries of Constellation Energy Group, Inc. The results of Oleander’s operations have been included in the financial statements since that date. The Company’s acquisition of the general and limited partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate purchase price of approximately $206 million, plus approximately $12 million of working capital and other adjustments. Plant Oleander is a dual-fueled generating plant in Brevard County, Florida with a nameplate capacity of 628 megawatts (MW). The entire output of Plant Oleander is sold under separate PPAs with Florida Power & Light Company (FPL) and Seminole Electric Cooperative, Inc. (Seminole). The PPA with FPL is for one unit and extends through the end of May 2007. The Seminole PPA is for the remaining three units at Oleander and extends through the end of 2009. In February 2006, FPL extended its PPA for approximately 160 MW through 2012 and Seminole signed a new PPA for approximately 320 MW of capacity through 2015.

Plant Franklin Unit 3 Construction Project

In May 2003, the Company entered into an agreement with Dynegy to resolve all outstanding matters related to capacity sales contracts with subsidiaries of Dynegy. Under the terms of the agreement, Dynegy made a cash termination payment of $80 million to the Company. The termination payments from Dynegy resulted in a one-time gain to the Company of approximately $50 million. As a result of the contract termination, the Company has completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. The length of the deferral period will depend on forecasted capacity needs and other wholesale market opportunities. As of December 31, 2005, the Company’s investment in Unit 3 of Plant Franklin was $171.5 million. The final outcome of this matter cannot now be determined.

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Southern Power Company and Subsidiary Companies 2005 Annual Report

3. JOINT OWNERSHIP AGREEMENTS

The Company is a 65 percent owner of Plant Stanton A, a combined-cycle project with 630 MWs. The unit is co-owned by the Orlando Utilities Commission (OUC) (28 percent), Florida Municipal Power Agency (3.5 percent), and Kissimmee Utility Authority (3.5 percent). The Company has a service agreement with SCS whereby SCS is responsible for the operations and maintenance of Plant Stanton A. As of December 31, 2005, $155.7 million was recorded in plant in service with associated accumulated depreciation of $10 million. The Company’s proportionate share of Plant Stanton A’s operating expense is included in the corresponding operating expenses in the statements of income.

     The Company will be a 65 percent owner of the gasifier island portion of the new IGCC project at OUC’s Stanton Energy Center site. OUC will own the remaining 35 percent of the gasifier and 100 percent of the combined cycle portion of the IGCC project. The Company will construct the project for OUC at a fixed price. OUC will purchase the Company’s 65 percent capacity in the gasification island for 20 years after the date of commercial operation. In addition, the Company will manage the operations of the project after construction is completed using a joint staff of OUC and SCS employees.

     A cooperative agreement with DOE was signed in February 2006, which provides for up to $235 million in funding from the DOE to be applied by the joint owners for the construction and demonstration of the gasification portion of the project. The DOE will provide the funding in four phases throughout the development and demonstration of the gasifier. The Company’s share of the total cost related to the gasifier portion of the project is currently estimated at approximately $121 million. The IGCC project, subject to National Environmental Policy Act review and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in 2010.

4. INCOME TAXES

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

     Details of the income tax provisions are as follows:

	2005		2004		2003
	(in thousands)
Total provision for income taxes:
Federal:
Current	$	40,468	$	40,492	$	64,044
Deferred		20,437		19,939		19,203
		60,905		60,431		83,247
State:
Current		7,310		8,933		10,426
Deferred		3,618		3,571		3,318
State manufacturer’s tax credits		—		—		(11,770	)
		10,928		12,504		1,974
Total	$	71,833	$	72,935	$	85,221

     The tax effects of temporary differences between the carrying amounts of assets and liabilities within the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2005			2004
	(in thousands)
Deferred tax liabilities:
Accelerated depreciation	$	(127,913	)	$	(101,840	)
Book/tax basis difference on asset transfer		(4,861	)		(6,455	)
Total		(132,774	)		(108,295	)
Deferred tax assets:
Book/tax basis differences on asset transfers		11,878			13,333
Other comprehensive loss on interest rate swaps		31,727			35,988
Levelized capacity revenues		14,221			13,819
Other		6,413			4,942
Total		64,239			68,082
Accumulated deferred income taxes in the balance sheets	$	(68,535	)	$	(40,213	)

     Deferred tax liabilities are primarily the result of property related timing differences and derivative hedging instruments. The transfer of the Plant McIntosh

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Southern Power Company and Subsidiary Companies 2005 Annual Report

construction project to Georgia Power and Savannah Electric in 2004 resulted in a deferred gain for federal income tax purposes. Georgia Power and Savannah Electric are reimbursing the Company for the related tax liability balance of $6.3 million. Of this total, $1.9 million is included in the balance sheet in Affiliated Accounts Receivable and the remainder is included in Other Affiliated Deferred Debits.

     Deferred tax assets consist primarily of timing differences related to the recognition of capacity revenues, and the tax impact related to the deferred loss on interest rate swaps reflected in Other Comprehensive Income. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from Georgia Power in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse Georgia Power for the related tax asset of $12.2 million. Of this total, $1.4 million is included in the balance sheet in Affiliated Accounts Payable and the remainder is included in Other Affiliated Deferred Credits.

     A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:

	2005			2004			2003
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		3.8			4.4			3.7
State manufacturer’s tax credits, net of federal effect		—			—			(3.2	)
Other		(0.3	)		0.1			—
Effective income tax rate		38.5	%		39.5	%		35.5	%

5. FINANCING

Bank Credit Arrangements

The Company has a $400 million unsecured syndicated revolving credit facility (Facility) expiring in April 2010. The purpose of the Facility is to provide liquidity support to the Company’s commercial paper program and other general corporate purposes. At December 31, 2005, the Company had $399 million available under the Facility.

     The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/8 of 1 percent. For the period ended December 31, 2005, the Company incurred approximately $0.8 million in expense from commitment fees under the Facility. Under a previous credit facility, for the periods ended December 31, 2004 and 2003, the Company incurred expenses of $2.1 million and $2.1 million from commitment fees, respectively.

     The Facility contains a covenant that requires a maximum 65 percent debt to capitalization ratio, as defined in the Facility. The Facility also contains a cross default provision that would be triggered if the Company defaulted on other indebtedness above a specified threshold. As of December 31, 2005, the Company was in compliance with all such covenants.

Dividend Restriction

The Facility also contains certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company’s projected cash flows from fixed priced capacity PPAs (as defined in the agreement) are at least 80 percent of total projected cash flows for the next twelve months or the Company’s debt to capitalization ratio is no greater than 60 percent. At December 31, 2005, the Company was in compliance with these ratios and had no restrictions on its ability to pay dividends.

Commercial Paper

The Company has the ability to borrow under a commercial paper program. For the periods ended December 31, 2005 and 2004, the peak commercial paper balance outstanding was $184.7 million and $114.5 million, respectively. The average amount outstanding was $63 million and $49.6 million in 2005 and 2004, respectively. The average annual interest rate was 3.7 percent in 2005 and 1.14 percent in 2004. As of December 31, 2005, the commercial paper program had an outstanding balance of $110.7 million. There was no commercial paper outstanding on December 31, 2004.

Financial Instruments

The Company enters into energy related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. The Company may enter into interest rate swaps to limit exposure to interest rate changes. Swaps related to variable rate securities or forecasted transactions are accounted for as cash flow hedges.

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Southern Power Company and Subsidiary Companies 2005 Annual Report

These swaps are generally structured to match the critical terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings.

     At December 31, 2005, the Company had no interest derivatives outstanding. The Company has deferred losses totaling $82.4 million in other comprehensive income that will be amortized to interest expense through 2013 over the life of the related senior notes. For the years 2005, 2004, and 2003, approximately $11.2 million, $10.4 million, and $5.5 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. During 2006, approximately $11.9 million of pre-tax losses are expected to be reclassified from other comprehensive income to interest expense.

     Fair value gains or losses for cash flow hedges are recorded in other comprehensive income and reclassified to fuel expense. There were no material amounts reclassified during any year presented. For the year 2006, the reclassifications from other comprehensive income to fuel expense are expected to be immaterial. There was no significant ineffectiveness recorded in earnings for any period presented. The Company has energy-related hedges in place through 2007. Additionally, there are deferred realized net hedging gains relating to capitalized costs and revenues during the construction of specific plants that will be reclassified from other comprehensive income to depreciation and amortization over the remaining life of the respective plants, which is approximately 32 years. For the years 2005, 2004, and 2003, approximately $0.3 million per year of pre-tax gains were reclassified from other comprehensive income to depreciation and amortization. For 2006, approximately $0.3 million of pre-tax gains are expected to be reclassified from other comprehensive income to depreciation and amortization.

6. COMMITMENTS

Construction Program

The Company currently estimates property additions to be $162.3 million, $265.2 million, and $221.0 million in 2006, 2007, and 2008, respectively. There are currently no plants actively under construction. See Note 2 under “Plant Franklin Unit 3 Construction Project” for additional information.

Long-Term Service Agreements

The Company has entered into several Long-Term Service Agreements (LTSAs) with General Electric (GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. In summary, the LTSAs provide that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

     In general, except for Plants Dahlberg and Oleander, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg and Oleander agreements are in effect through the first hot gas path inspections and last combustion inspections, respectively, of each unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements are $1.1 billion over the remaining term of the agreements, which may range up to 30 years per unit. However, the LTSAs contain various cancellation provisions at the Company’s option.

     Payments made to GE prior to the performance of any planned inspections are recorded as a long-term prepayment in Deferred Charges and Other Assets on the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

Fuel Commitments

SCS, as agent for the retail operating companies and the Company, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities. In most cases, these contracts contain provisions for firm transportation costs, storage costs, minimum purchase levels and other financial commitments.

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Southern Power Company and Subsidiary Companies 2005 Annual Report

     Natural gas purchase commitments contain given volumes with prices based on various indices at the actual time of delivery. Amounts included in the chart below represent estimates based on the New York Mercantile Exchange future prices at December 31, 2005.

	Fuel
Year	Purchases
	(in thousands)
2006	$	20,928
2007		21,272
2008		20,766
2009		18,589
2010		27,110
2011 and beyond		300,057
Total	$	408,722

Additional commitments for fuel will be required to supply the Company’s future needs.

     Acting as an agent for all of Southern Company’s retail operating companies, the Company and Southern Company Gas, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the retail operating companies, the Company and Southern Company Gas may be jointly and severally liable. The creditworthiness of the Company and Southern Company Gas is currently inferior to the creditworthiness of the retail operating companies; therefore, Southern Company has entered into keep-well agreements with each of the retail operating companies to insure they will not subsidize nor be responsible for any costs, losses, liabilities or damages resulting from the inclusion of the Company and Southern Company Gas as a contracting party under these agreements.

7. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2005 and 2004 is as follows:

	Operating		Operating
Quarter Ended	Revenues		Income		Net Income
	(in thousands)
March 2005	$	152,821	$	56,745	$	23,073
June 2005		149,226		60,611		25,234
September 2005		265,611		84,555		39,227
December 2005		213,346		61,656		27,257
March 2004	$	175,605	$	56,415	$	27,185
June 2004		182,749		50,562		22,417
September 2004		188,941		79,260		37,322
December 2004		154,016		61,886		24,584

     The Company’s business is influenced by seasonal weather conditions. The Company had approximately 4,775 MWs and 5,403 MWs of generating capacity in service through May and December 2005, respectively.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2001-2005
Southern Power Company and Subsidiary Companies 2005 Annual Report

	2005		2004			2003		2002		2001
Operating Revenues (in thousands):
Sales for resale — non-affiliates	$	223,058	$	266,463		$	278,559	$	114,919	$	26,390
Sales for resale — affiliates		556,664		425,065			312,586		183,111		2,906
Total revenues from sales of electricity		779,722		691,528			591,145		298,030		29,296
Other revenues		1,282		9,783			90,635		738		5
Total	$	781,004	$	701,311		$	681,780	$	298,768	$	29,301
Net Income (in thousands)	$	114,791	$	111,508		$	155,149	$	54,270	$	8,207
Cash Dividends on Common Stock (in thousands)	$	72,400	$	207,000		$	—	$	—	$	—
Return on Average Common Equity (percent)		13.68		12.23			17.65		8.94		3.51
Total Assets (in thousands)	$	2,302,976	$	2,067,013		$	2,409,285	$	2,085,976	$	822,857
Gross Property Additions (in thousands)	$	241,103	$	115,606		$	344,362	$	1,214,677	$	765,511
Capitalization (in thousands):
Common stock equity	$	866,343	$	811,611		$	1,011,476	$	746,604	$	466,993
Long-term debt		1,099,520		1,099,435			1,149,112		955,879		293,205
Total (excluding amounts due within one year)	$	1,965,863	$	1,911,046		$	2,160,588	$	1,702,483	$	760,198
Capitalization Ratios (percent):
Common stock equity		44.1		42.5			46.8		43.9		61.4
Long-term debt		55.9		57.5			53.2		56.1		38.6
Total (excluding amounts due within one year)		100.0		100.0			100.0		100.0		100.0
Security Ratings:
Unsecured Long-Term Debt -
Moody’s	Baa1		Baa1			Baa1		Baa1			—
Standard and Poor’s	BBB+		BBB+			BBB+		BBB+			—
Fitch	BBB+		BBB+			BBB+		BBB+			—
Kilowatt-Hour Sales (in thousands):
Sales for resale — non-affiliates		3,932,638		5,369,261			6,057,053		1,240,290		164,926
Sales for resale — affiliates		6,355,249		6,583,017			5,430,973		3,607,107		69,307
Total		10,287,887		11,952,278			11,488,026		4,847,397		234,233
Average Revenue Per Kilowatt-Hour (cents)		7.58		5.79			5.15		6.15		12.51
Plant Nameplate Capacity Ratings (year-end) (megawatts)		5,403		4,775			4,775		2,408		800
Maximum Peak-Hour Demand (megawatts):
Winter		2,037		2,098			2,077		949		—
Summer		2,420		2,740			2,439		1,426		—
Annual Load Factor (percent)		48.9		54.4	��		54.9		51.1		—
Plant Availability (percent)		97.6		97.9			96.8		95.1		83.7
Source of Energy Supply (percent):
Gas		72.6		61.9			53.4		77.4		100.0
Purchased power -
From non-affiliates		9.6		24.7			30.5		5.9		—
From affiliates		17.8		13.4			16.1		16.7		—
Total		100.0		100.0			100.0		100.0		100.0

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PART III

Items 10, 11, 12, (except for “Equity Compensation Plan Information” which is included herein), 13 and 14 for Southern Company are incorporated by reference in Southern Company’s definitive Proxy Statement relating to the 2006 Annual Meeting of Stockholders. Specifically, reference is made to “Nominees for Election as Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” for Item 13 and “Principal Public Accounting Firm Fees” for Item 14. The ages of Directors and Executive Officers set forth below are as of December 31, 2005.

     Additionally, Items 10, 11, 12, 13 and 14 for Alabama Power and Mississippi Power are incorporated by reference to the Information Statements of Alabama Power and Mississippi Power relating to each of their respective 2006 Annual Meetings of Shareholders. Specifically, reference is made to “Nominees for Election as Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation Information” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” for Item 13 and “Principal Public Accounting Firm Fees” for Item 14.

     Items 10, 11, 12 and 13 for Southern Power are omitted pursuant to General Instruction I(2)(c) of Form 10-K.

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

GEORGIA POWER

Identification of directors of Georgia Power.

Michael D. Garrett
President, Chief Executive Officer and Director
Age 56
Served as Director since 2004

Gus H. Bell, III(1)
Age 68
Nominee

Robert L. Brown, Jr. (2)
Age 54
Served as Director since 2003

Ronald D. Brown(2)
Age 52
Served as Director since 2004

Anna R. Cablik(2)
Age 53
Served as Director since 2001

David M. Ratcliffe(2)
Age 57
Served as Director since 1999

D. Gary Thompson(2)
Age 59
Served as Director since 2003

Richard W. Ussery(2)
Age 58
Served as Director since 2001

William J. Vereen(2)
Age 65
Served as Director since 1988

E. Jenner Wood, III(2)
Age 54
Served as Director since 2001

(1) Mr. Bell is a nominee to Georgia Power’s Board of Directors to be elected at the 2006 annual meeting of Georgia Power shareholders. (2) No position other than director.

     Each of the above (other than Mr. Bell) is currently a director of Georgia Power, serving a term running from the last annual meeting of Georgia Power’s shareholders (May 18, 2005) for one year until the next annual meeting or until a successor is elected and qualified.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of Georgia Power acting solely in their capacities as such.

III-1

Identification of executive officers of Georgia Power.

Michael D. Garrett
President, Chief Executive Officer and Director
Age 56
Served as Executive Officer since 2003

William C. Archer, III(1)
Executive Vice President
Age 57
Served as Executive Officer since 1995

Mickey A. Brown
Executive Vice President
Age 58
Served as Executive Officer since 2001

Cliff S. Thrasher
Executive Vice President, Chief Financial Officer and Treasurer
Age 55
Served as Executive Officer since 2005

Christopher C. Womack(2)
Executive Vice President
Age 47
Served as Executive Officer since 2001

Judy M. Anderson
Senior Vice President
Age 57
Served as Executive Officer since 2001

Richard L. Holmes
Senior Vice President
Age 54
Served as Executive Officer since 2003

Douglas E. Jones(3)
Senior Vice President
Age 47
Served as Executive Officer since 2005

James H. Miller, III
Senior Vice President and General Counsel
Age 56
Served as Executive Officer since 2004

Leslie R. Sibert
Vice President
Age 43
Served as Executive Officer since 2001

Gene L. Ussery, Jr.
Vice President
Age 56
Served as Vice President since 2005

(1)	Mr. Archer will retire as Executive Vice President, effective March 19, 2006.
(2)	Mr. Womack was elected Executive Vice President of External Affairs, effective March 11, 2006.
(3)	Mr. Jones was elected Senior Vice President of Fossil and Hydro Generation, effective March 11, 2006.

     Each of the above is currently an executive officer of Georgia Power, serving a term running from the last annual organizational meeting of the directors (May 18, 2005) for one year until the next annual meeting or until their successors are elected and qualified, except for Messrs. Jones and Womack whose elections will be effective on March 11, 2006.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Georgia Power acting solely in their capacity as such.

Identification of certain significant employees.
None.

Family relationships.
None.

Business experience.

Unless noted otherwise, each director has served in his or her present position for at least the past five years.

Michael D. Garrett- President and Chief Executive Officer of Georgia Power since April 2004. He previously served as President of Georgia Power from January 2004 to April 2004; President and Chief Executive Officer and Director of Mississippi Power from May 2001 to December 2003, and Executive Vice President — Customer Service of Alabama Power from January 2000 to May 2001.

III-2

Gus H. Bell, III— Chairman of the Board, President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, A Bell Company (specializing in environmental, transportation, industrial, structural, architectural and civil engineering), Savannah, Georgia since 1986. Advisory Director of SunTrust Bank of Savannah. Mr. Bell also serves as a director of Savannah Electric.

Robert L. Brown, Jr.— President and Chief Executive Officer of R.L. Brown & Associates Inc. (architectural/construction management company), Decatur, Georgia. He is a Director of Citizens Trust Bank.

Ronald D. Brown— President and Chief Executive Officer of Atlanta Life Financial Group (financial services company), Atlanta, Georgia. He previously served as Chief Executive Officer and Managing Partner of the Variant Group LLC, Atlanta, Georgia, from 2001 to 2004 and Chief Executive Officer of SYNAVANT Inc., Atlanta, Georgia, from 2000 to 2001.

Anna R. Cablik— President of Anatek, Inc. , Marietta, Georgia, and Anasteel & Supply Company, LLC, Ellenwood, Georgia (suppliers of fabricated concrete reinforcing steel); President of MassAna Construction (general construction), Marietta, Georgia; and a partner of PanAmerican Logistics, PanAmerican International and Atlanta International Foods, Atlanta, Georgia. She is a Director of Branch Banking and Trust Company.

David M. Ratcliffe— Chairman of the Board, President and Chief Executive Officer of Southern Company since July 2004. He previously served as President of Southern Company from April 2004 until July 2004; Executive Vice President of Southern Company from May 1999 until April 2004; President and Chief Executive Officer of Georgia Power from May 1999 to January 2004 and Chairman and Chief Executive Officer of Georgia Power from January 2004 to April 2004. He is a Director of CSX Corporation, Alabama Power and Southern Power.

D. Gary Thompson— Retired, Chief Executive Officer of Georgia Banking, Wachovia Bank, N.A., Atlanta, Georgia, and Executive Vice President of Wachovia Corporation, Charlotte, North Carolina, from June 1995 until December 2004. He is a Director of American Family Life Assurance Company of Columbus (AFLAC).

Richard W. Ussery— Retired, Chairman of the Board of Total Systems Services (TSYS) (credit card processing facility), Columbus, Georgia, from January 2004 until January 2006. He previously served as Chairman of the Board and Chief Executive Officer of TSYS from 1992 to 2004. He is a Director of TSYS.

William J. Vereen— Chairman, President and Chief Executive Officer of Riverside Manufacturing Company (manufacturer and sales of uniforms), Moultrie, Georgia. He is a Director of Gerber Scientific, Inc.

E. Jenner Wood, III— Chairman, President and Chief Executive Officer of SunTrust Bank, Central Group and Executive Vice President of SunTrust Banks Inc., Atlanta, Georgia. He previously served as President of SunTrust Bank, Atlanta and SunTrust Bank Georgia from 2000 to 2001. He is a Director of Oxford Industries, Inc. and Crawford & Company.

William C. Archer, III —Executive Vice President of External Affairs since 1995 and will retire effective March 19, 2006.

Mickey A. Brown —Executive Vice President of the Customer Service Organization since January 2005. He previously served as Senior Vice President of Distribution from 2001 to 2005; and Vice President, Distribution from 2000 to 2001.

Cliff S. Thrasher —Executive Vice President, Chief Financial Officer and Treasurer since March 2005. He previously served as Senior Vice President, Comptroller and Chief Financial Officer of Southern Power from November 2002 to March 2005 and Vice President of SCS from June 2002 to March 2005; and Vice President, Comptroller and Chief Accounting Officer of Georgia Power from September 1995 to June 2002.

Christopher C. Womack— Executive Vice President of External Affairs, effective March 11, 2006. He currently serves as Senior Vice President of Fossil and Hydro Generation and Senior Production Officer since 2001. He previously served as Senior Vice President of Human Resources of SCS from 1998 to 2001.

III-3

Judy M. Anderson —Senior Vice President of Charitable Giving since 2001. She previously served as Vice President and Corporate Secretary of Georgia Power from 1989 to 2001.

Richard L. Holmes —Senior Vice President of Metro Atlanta Region, since January 2006. He served as Senior Vice President of Metro Atlanta Region, Diversity and Corporate Relations from 2005 to 2006. He previously served as Senior Vice President of Corporate Services from 2003 to 2005; Vice President of Administrative Services from 2002 to 2003; and Vice President of Region Operations from 2000 to 2002.

Douglas E. Jones —Senior Vice President of Fossil and Hydro Generation, effective March 11, 2006. He currently serves as Senior Vice President of Customer Service and Sales since January 2005. He previously served as Executive Vice President of Southern Power from January 2004 to January 2005; Senior Vice President, Southern Company Energy Marketing from December 2001 to January 2004; and Vice President, Southern Company Wholesale Energy from December 1998 to 2001.

James H. Miller, III —Senior Vice President and General Counsel since March 2004. He previously served as Vice President and Associate General Counsel for SCS and Senior Vice President, General Counsel and Assistant Secretary of Southern Power from 2001 to 2004; and Senior Vice President, Alabama Power — Birmingham Division from 1999 to 2001. He is a Director of Fidelity Southern Corporation.

Leslie R. Sibert— Vice President, Transmission since 2001. She previously served as Decatur Region Manager from 1999 to 2001.

Gene L. Ussery, Jr.— Vice President, Distribution since February 2005. He previously served as Vice President and Senior Production Officer of Mississippi Power and Gulf Power from 2002 to 2005 and Vice President, Power Generation and Delivery, Mississippi Power from 2000 to 2002.

Involvement in certain legal proceedings.
None.

Section 16(a) Beneficial Ownership Reporting
Compliance.
None.

GULF POWER

Identification of directors of Gulf Power.

Susan N. Story
President and Chief Executive Officer
Age 45
Served as Director since 2003

C. LeDon Anchors(1)
Age 65
Served as Director since 2001

William C. Cramer, Jr.(1)
Age 53
Served as Director since 2002

Fred C. Donovan, Sr. (1)
Age 65
Served as Director since 1991

William A. Pullum(1)
Age 58
Served as Director since 2001

Winston E. Scott(1)
Age 55
Served as Director since 2003

(1) No position other than director.

     Each of the above is currently a director of Gulf Power, serving a term running from the last annual meeting of Gulf Power’s shareholders (May 18, 2005) for one year until the next annual meeting or until a successor is elected and qualified.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.

Identification of executive officers of Gulf Power.

Susan N. Story
President and Chief Executive Officer
Age 45
Served as Executive Officer since 2003

III-4

Francis M. Fisher, Jr.
Vice President – Customer Operations
Age 57
Served as Executive Officer since 1989

P. Bernard Jacob
Vice President – External Affairs and
Corporate Services
Age 51
Served as Executive Officer since 2003

Ronnie R. Labrato
Vice President and Chief Financial Officer
Age 52
Served as Executive Officer since 2000

Penny M. Manuel
Vice President – Senior Production Officer
Age 43
Served as Executive Officer since 2005

     Each of the above is currently an executive officer of Gulf Power, serving a term running from the last annual organizational meeting of the directors (July 28, 2005) for one year until the next annual meeting or until a successor is elected and qualified.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with officers of Gulf Power acting solely in their capacities as such.

Identification of certain significant employees.
None.

Family relationships.
None.

Business experience.

Unless noted otherwise, each director has served in his or her present position for at least the past five years.

Susan N. Story– President and Chief Executive Officer since 2003. She previously served as Executive Vice President of SCS from January 2001 to April 2003; Senior Vice President of Southern Power from November 2002 to April 2003; Vice President of SCS from May 2000 to January 2001.

C. LeDon Anchors- Attorney and President of Anchors Smith Grimsley, Attorneys at Law, Fort Walton Beach, Florida. He is Chairman of Regions Bank of Okaloosa County.

William C. Cramer, Jr. — President and Owner of Tommy Thomas Chevrolet, Panama City, Florida.

Fred C. Donovan, Sr. — Chairman and Chief Executive Officer of Baskerville-Donovan, Inc. (an architectural and engineering firm), Pensacola, Florida.

William A. Pullum- Broker/President of Bill Pullum Realty, Inc., Navarre, Florida, and Owner, President and Director of Cowboy’s Steakhouse, Navarre, Florida.

Winston E. Scott- Executive Director of the Florida Space Authority, Cape Canaveral, Florida. He previously served as a professor and associate dean with the Florida Agriculture and Mechanical University and Florida State University (FSU) College of Engineering in 2003, Vice President for Student Affairs at FSU from 2000 until 2003 and Associate Vice President with the Division of Student Affairs at FSU from 1999 to 2000.

Francis M. Fisher, Jr.
Vice President of Customer Operations since 1996.

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

Ronnie R. Labrato- Vice President and Chief Financial Officer since January 14, 2006. He previously served as Vice President, Chief Financial Officer and Comptroller from 2001 to 2006.

Penny M. Manuel —Vice President and Senior Production Officer since February 2005. She previously served as Director, Human Resources for Southern Company Generation from 2002 until February 2005; Vice President and Chief Information Officer, Alabama Power, and Regional Chief Information Officer for Southern Nuclear and SCS from 2001 until 2002; Manager, Business Technology Requirements, Southern Company Generation from 2000 to 2001.

III-5

Involvement in certain legal proceedings.
None.

Section 16(a) Beneficial Ownership Reporting Compliance.
None.

SAVANNAH ELECTRIC

Identification of directors of Savannah Electric.

W. Craig Barrs
Age 48
Served as Director since 2005

Gus H. Bell, III(1)
Age 68
Served as Director since 1999

Archie H. Davis(1)
Age 64
Served as Director since 1997

Robert B. Miller, III(1)
Age 60
Served as Director since 1983

Arnold M. Tenenbaum(1)
Age 69
Served as Director since 1977

(1) No position other than director.

     Each of the above is currently a director of Savannah Electric, serving a term running from the last annual meeting of Savannah Electric’s stockholder (April 29, 2005) for one year until the next annual meeting or until a successor is elected and qualified, except for Mr. Barrs who was elected on December 13, 2005.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as a director or nominee, other than any arrangements or understandings with directors or officers of Savannah Electric acting solely in their capacities as such.

Identification of executive officers of Savannah Electric.

W. Craig Barrs(1)
President, Chief Executive Officer and Director
Age 48
Served as Executive Officer since 2005

W. Miles Greer
Vice President
Age 62
Served as Executive Officer since 1985

Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 54
Served as Executive Officer since 1994

     Each of the above is currently an executive officer of Savannah Electric, serving a term running from the last annual organizational meeting of the directors (August 4, 2005) for one year, except for Mr. Barrs whose election was on December 13, 2005.

(1) Mr. Barrs was elected President and Chief Executive Officer, effective December 13, 2005. He will be named Vice President of Georgia Power’s new coastal region when the merger of Georgia Power and Savannah Electric is completed.

     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of Savannah Electric acting solely in their capacities as such.

Identification of certain significant employees.
None.

Family relationships.
None.

Business experience.

W. Craig Barrs
President and Chief Executive Officer since December 2005. He previously served as Vice President of Community and Economic

III-6

Development for Georgia Power from November 2002 to December 2005; Assistant to the President of Georgia Power from June 2002 to November 2003; and Regulatory Affairs Manager of Georgia Power from March 1999 to June 2002.

Gus H. Bell, III— Chairman of the Board, President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, A Bell Company (specializing in environmental, transportation, industrial, structural, architectural and civil engineering), Savannah, Georgia since 1986. Advisory Director of SunTrust Bank of Savannah.

Archie H. Davis— President Emeritus of the Savannah Bancorp, Inc. since April 2003; Director of Savannah Bancorp, Inc., Savannah, Georgia since 1990; and Director of The Savannah Bank N.A. since 1990. He previously served as President and Chief Executive Officer and Director of Savannah Bancorp, Inc., Savannah, Georgia from 1990 to 2003; Chief Executive Officer of The Savannah Bank, N.A. from 2002 to 2003; and President and Chief Executive Officer of The Savannah Bank, N.A. from 1990 to 2002.

Robert B. Miller, III —President of American Building Systems, Inc. (general contracting services), Savannah, Georgia, since 1992.

Arnold M. Tenenbaum —Retired from Chatham Steel Corporation in 2003. He previously served as President and Director of Chatham Steel Corporation (specializing in carbon, stainless and specialty steel), Savannah, Georgia from 2001 to 2003; and President and Chief Executive Officer of Chatham Steel Corporation from 1981 to 2001. He is Chairman of the Board of Directors of FCB Financial Corp., the holding company of First Chatham Bank, Savannah, Georgia.

W. Miles Greer —Vice President of Customer Operations and External Affairs since 1998.

Kirby R. Willis —Vice President, Treasurer and Chief Financial Officer since 1994 and Assistant Corporate Secretary since 1998.

Involvement in certain legal proceedings.
None.

Section 16(a) Beneficial Ownership Reporting Compliance.
None.

Code of Ethics

The registrants collectively have adopted a code of business conduct and ethics that applies to each director, officer and employee of the registrants and their subsidiaries. The code of business conduct and ethics can be found on Southern Company’s website located athttp://www.southerncompany.com. The code of business conduct and ethics is also available free of charge in print to any shareholder upon request. Any amendment to or waiver from the code of ethics that applies to executive officers and directors will be posted on the website.

Corporate Governance Guidelines and Committee Charters

Southern Company has adopted corporate governance guidelines and committee charters. The corporate governance guidelines and the charters of Southern Company’s Audit Committee, Governance Committee and Compensation and Management Succession Committee can be found on Southern Company’s website located athttp://www.southerncompany.com.The corporate governance guidelines and charters are also available free of charge in print to any shareholder upon request.

III-7

Item 11. EXECUTIVE COMPENSATION

Georgia Power Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the five most highly compensated executive officers serving during 2005.

	ANNUAL COMPENSATION									LONG-TERM COMPENSATION
			��							Number of
										Securities
										Underlying		Long-Term
								Other Annual		Stock		Incentive		All Other
Name and								Compensation		Options		Payouts		Compensation
Principal Position	Year			Salary($)		Bonus($)		($)1		(Shares)		($)2		($)3
Michael D. Garrett President, Chief		2005			526,125		850,669		6,275		78,565		139,687		27,974
Executive Officer,		2004			498,323		764,213		161,355		53,419		231,474		121,563
Director
James H. Miller, III		2005			298,553		319,785		21,182		27,073		129,989		41,456
Senior Vice President,		2004			291,698		294,772		79,597		27,361		192,587		14,546
General Counsel
William C. Archer		2005			293,106		313,951		47,061		26,579		137,031		91,126
Executive Vice		2004			276,867		291,928		3,716		25,582		168,992		14,412
President		2003			262,894		267,282		3,142		26,560		234,317		14,029
Christopher C. Womack		2005			290,472		288,552		57,373		26,413		135,237		31,049
Executive Vice		2004			278,010		250,897		8,530		26,310		218,962		27,630
President		2003			266,274		246,799		11,074		26,923		247,563		23,648
Mickey A. Brown		2005			286,403		308,874		2,680		26,199		69,032		15,155
Executive Vice		2004			243,714		224,990		3,227		18,820		119,742		13,117
President		2003			226,601		216,296		2,492		18,091		141,113		11,080
C. B. Harreld4 Executive Vice		2005			286,867		302,383		18,777		25,498		57,204		37,738
President, Chief		2004			263,053		277,362		5,156		24,306		87,902		13,902
Financial Officer		2003			240,504		231,977		10,153		19,117		111,832		28,027

1	This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column. In 2005, the amount for Mr. Womack includes country club dues of $25,669. In 2004, the amount for Messrs. Garrett and Miller also includes country club dues of $60,000 and $37,500, respectively.
2	Payout of performance dividend equivalents on stock options granted after 1996 that were held by the executive at the end of the performance periods under the Southern Company’s Omnibus Incentive Compensation Plan (“Omnibus Incentive Compensation Plan”) for the four-year performance periods ended December 31, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five percent of the common stock dividend paid during the last year of the performance period if total shareholder return over the four-year period, compared to a group of other large utility companies, is above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
3	Contributions in 2005 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) are as follows:

Name	ESP		ESOP		SBP
Michael D. Garrett	$	9,450	$	773	$	17,751
James H. Miller, III		9,450		773		6,233
William C. Archer		8,769		773		6,584
Christopher C. Womack		9,450		773		5,826
Mickey A. Brown		9,450		773		4,932
C. B. Harreld		9,169		773		1,796

In 2005, Messrs. Miller, Archer, Womack and Harreld received additional incentive compensation of $25,000, $75,000, $15,000 and $26,000, respectively. In 2004, Messrs. Garrett and Womack received additional incentive compensation in the amounts of $25,000 and $12,500, respectively. In 2004, Mr. Garrett received additional relocation assistance of $71,698. In 2003, Messrs. Womack and Harreld received additional incentive compensation of $10,000 and $15,554, respectively.

4

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

III-8

Gulf Power Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the five most highly compensated executive officers serving during 2005.

	ANNUAL COMPENSATION								LONG-TERM COMPENSATION
									Number of
									Securities		Long-
Name									Underlying		Term
and							Other Annual		Stock		Incentive		All Other
Principal							Compensation		Options		Payouts		Compensation
Position	Year		Salary($)		Bonus($)		($)5		(Shares)		($)6		($)7
Susan N. Story President, Chief		2005		332,029		348,515		3,651		38,529		75,816		17,571
Executive Officer,		2004		313,256		254,668		6,811		37,837		156,306		16,531
Director		2003		297,771		245,241		3,572		24,978		138,695		14,203
Francis M. Fisher, Jr.		2005		230,294		180,481		2,597		17,102		75,503		11,603
Vice President		2004		222,455		135,067		3,470		17,200		104,933		13,987
		2003		214,404		130,248		2,436		17,737		135,659		10,772
Ronnie R. Labrato		2005		211,120		165,757		6,200		15,707		44,197		20,890
Vice President and		2004		202,063		122,861		2,399		15,646		47,631		12,986
Chief Financial Officer		2003		183,716		108,945		21		11,530		57,461		9,217
P. Bernard Jacob		2005		190,869		149,993		8,439		14,213		21,441		24,711
Vice President		2004		180,415		109,874		3,093		14,090		25,664		12,112
		2003		167,967		94,904		2,471		6,678		22,150		7,734
Penny M. Manuel8		2005		163,737		128,128		5,524		5,961		20,159		25,196
Vice President
Gene L. Ussery, Jr.9		2005		252,160		243,312		6,553		18,944		61,442		18,290
Vice President		2004		230,587		187,621		10,534		17,886		87,520		27,759
		2003		218,752		182,806		8,388		18,129		110,711		11,488

5	This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column.
6	Payout of performance dividend equivalents on stock options granted after 1996 that were held by the executive at the end of the performance periods under the Southern Company’s Omnibus Incentive Compensation Plan (“Omnibus Incentive Compensation Plan”) for the four-year performance periods ended December 31, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five percent of the common stock dividend paid during the last year of the performance period if total shareholder return over the four-year period, compared to a group of other large utility companies, is above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
7	Contributions in 2005 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) are as follows:

Name	ESP		ESOP		SBP
Susan N. Story	$	9,450	$	773	$	7,348
Francis M. Fisher, Jr.		8,703		773		2,127
Ronnie R. Labrato		9,408		773		709
P. Bernard Jacob		8,589		773		349
Penny M. Manuel		7,221		773		202
Gene L. Ussery, Jr.		9,450		773		3,067

	In 2005, this amount for Messrs. Labrato, Jacob and Ussery includes additional incentive compensation of $10,000, $15,000 and $5,000, respectively, and for Ms. Manuel includes incentive compensation of $17,000 related to relocation. In 2004, the amounts for Messrs. Fisher, Labrato and Jacob included additional incentive compensation of $3,000, $3,000 and $3,000, respectively.
8	Ms. Manuel became an executive officer of Gulf Power in February 2005.
9	Mr. Ussery resigned from Gulf Power in February 2005 and was elected a Vice President of Georgia Power in February 2005.

III-9

Savannah Electric Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the two most highly compensated executive officers serving during 2005.

	ANNUAL COMPENSATION								LONG-TERM COMPENSATION
									Number of
									Securities		Long-
Name									Underlying		Term
and							Other Annual		Stock		Incentive		All Other
Principal							Compensation		Options		Payouts		Compensation
Position	Year		Salary($)		Bonus($)		($)10		(Shares)		($)11		($)12
Anthony R. James13		2005		273,741		252,006		3,325		31,709		106,779		14,710
Chairman		2004		260,755		214,741		3,403		31,435		158,804		13,881
		2003		248,342		183,462		3,168		32,015		164,732		11,956
W. Craig Barrs14		2005		175,155		150,908		797		10,162		31,164		8,729
President, Chief Executive Officer, Director
W. Miles Greer		2005		209,882		128,342		166		12,111		42,640		25,613
Vice President		2004		203,900		111,487		57		12,240		87,556		23,507
		2003		198,238		97,376		1,716		12,744		111,890		24,702
Kirby R. Willis Vice President, Chief Financial Officer,		2005		193,440		118,287		924		11,162		39,213		16,010
Treasurer, Assistant		2004		187,827		82,202		748		11,281		61,834		15,602
Corporate Secretary		2003		182,109		89,491		2,207		11,712		68,470		14,634

10	This column reports tax reimbursements on certain perquisites and personal benefits as well as on additional incentive compensation, if applicable. Additional incentive compensation is reported in the All Other Compensation Column.
11	Payout of performance dividend equivalents on stock options granted after 1996 that were held by the executive at the end of the performance periods under the Southern Company’s Omnibus Incentive Compensation Plan (“Omnibus Incentive Compensation Plan”) for the four-year performance periods ended December 31, 2003, 2004 and 2005, respectively. Effective January 1, 2005, dividend equivalents can range from approximately five percent of the common stock dividend paid during the last year of the performance period if total shareholder return over the four-year period, compared to a group of other large utility companies, is above the 10th percentile to 100 percent of the dividend paid if it reaches the 90th percentile. For eligible stock options held on December 31, 2003, 2004 and 2005, all named executives earned a payout of $1.385, $1.22 and $0.83 per option, respectively.
12	Contributions in 2005 to the Employee Savings Plan (ESP), Employee Stock Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) or Above-Market Earnings on deferred compensation (AME) are as follows:

Name	ESP		ESOP		SBP or AME
Anthony R. James	$	9,216	$	773	$	4,621
W. Craig Barrs		7,362		773		494
W. Miles Greer		9,445		773		15,295
Kirby R. Willis		7,935		679		7,296

	In 2005, this amount for Messrs. James, Greer and Willis includes a $100 safety award.
13	Mr. James resigned as President and Chief Executive Officer of Savannah Electric effective December 13, 2005 and was elected Chairman of Savannah Electric’s board of directors from December 13, 2005 until January 31, 2006. In addition, Mr. James was elected an Executive Vice President of SCS on December 13, 2005.
14	Mr. Barrs was elected President and Chief Executive Officer of Savannah Electric effective December 13, 2005.

III-10

STOCK OPTION GRANTS IN 2005

The following table sets forth all stock option grants to the named executive officers during the year ending December 31, 2005.

	Individual Grants				Grant Date Value
			% of Total
	# of Securities		Options
	Underlying		Granted to		Exercise
	Options		Employee in		or Base Price		Expiration		Grant Date
Name	Granted15		Fiscal Year16		($/Sh)15		Date15		Present Value17
Georgia Power
Michael D. Garrett		78,565		5.6	$	32.70		02/18/2015	$	306,404
James H. Miller, III		27,073		1.9	$	32.70		02/18/2015		105,585
William C. Archer		26,579		1.9	$	32.70		02/18/2015		103,658
Christopher C. Womack		26,413		1.9	$	32.70		02/18/2015		103,011
Mickey A. Brown		26,199		1.9	$	32.70		02/18/2015		102,176
C. B. Harreld		25,498		1.8	$	32.70		02/18/2015		99,442
Gulf Power
Susan N. Story		38,529		15.4	$	32.70		02/18/2015		150,263
Francis M. Fisher, Jr.		17,102		6.8	$	32.70		02/18/2015		66,698
Ronnie R. Labrato		15,707		6.3	$	32.70		02/18/2015		61,257
P. Bernard Jacob		14,213		5.7	$	32.70		02/18/2015		55,431
Penny M. Manuel		5,961		2.4	$	32.70		02/18/2015		23,248
Gene L. Ussery, Jr.		18,944		7.5	$	32.70		02/18/2015		73,882
Savannah Electric
Anthony R. James		31,709		26.2	$	32.70		02/18/2015		123,665
W. Craig Barrs		10,162		8.4	$	32.70		02/18/2015		39,632
W. Miles Greer		12,111		10.0	$	32.70		02/18/2015		47,233
Kirby R. Willis		11,162		9.2	$	32.70		02/18/2015		43,532

15	Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 18, 2005 and vest annually at a rate of one-third on the anniversary date of the grant. Grants fully vest upon termination as a result of death, total disability or retirement and expire five years after retirement, three years after death or total disability or their normal expiration date if earlier. The exercise price is the average of the high and low price of Southern Company’s common stock on the date granted. Options may be transferred to a revocable trust.
16	A total of 1,411,442, 250,874 and 120,986 stock options were granted in 2005 to the employees of Georgia Power, Gulf Power and Savannah Electric, respectively.
17	Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on the market value of Southern Company’s common stock at a future date. Significant assumptions are shown below:

	Risk-free	Dividend	Expected
Volatility	rate of return	Yield	Term
17.9%	3.87%	4.38%	5 years

III-11

AGGREGATED STOCK OPTION EXERCISES IN 2005 AND YEAR-END OPTION VALUES

The following table sets forth information concerning options exercised during the year ending December 31, 2005 by the named executive officers and the value of unexercised options held by them as of December 31, 2005.

	Shares				Number of Securities Underlying				Value of Unexercised
	Acquired				Unexercised Options at Fiscal				In-the-Money Options
	on		Value		Year-End (#)				At Year-End ($)18
Name	Exercise (#)		Realized ($)19		Exercisable		Unexercisable		Exercisable		Unexercisable
Georgia Power
Michael D. Garrett		100,000		1,013,825		38,885		129,413		227,735		422,774
James H. Miller, III		28,318		395,271		101,644		54,969		966,236		204,586
William C. Archer		0		0		112,611		52,486		1,206,509		192,453
Christopher C. Womack		42,954		821,660		110,009		52,927		1,169,434		195,387
Mickey A. Brown		41,177		495,869		38,396		44,775		296,584		150,577
C. B. Harreld		28,628		249,479		20,847		48,074		124,296		169,936
Gulf Power
Susan N. Story		75,305		858,273		19,265		72,079		107,047		251,962
Francis M. Fisher, Jr.		12,146		178,541		56,487		34,480		521,513		127,724
Ronnie R. Labrato		1,500		14,758		23,269		29,980		172,718		106,398
P. Bernard Jacob		9,417		75,180		0		25,832		0		87,848
Penny M. Manuel		0		0		12,380		11,908		95,509		43,883
Gene L. Ussery, Jr.		16,656		185,802		37,115		36,911		285,964		134,257
Savannah Electric
Anthony R. James		33,227		462,548		65,312		63,337		503,065		233,391
W. Craig Barrs		11,619		158,890		17,312		20,235		127,802		74,479
W. Miles Greer		32,505		447,151		26,854		24,519		208,571		91,054
Kirby R. Willis		14,601		184,301		24,659		22,586		191,444		83,843

18

This column represents the excess of the fair market value of Southern Company’s common stock of $34.53 per share, as of December 31, 2005, above the exercise price of the options. The Exercisable column reports the “value” of options that are vested and therefore could be exercised. The Unexercisable column reports the “value” of options that are not vested and therefore could not be exercised as of December 31, 2005.

19

The “Value Realized” is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares at the time of exercise above the exercise price.

III-12

DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE

Pension Plan Table. The following table sets forth the estimated annual pension benefits payable at normal retirement age under Southern Company’s qualified Pension Plan, as well as non-qualified supplemental benefits, based on the stated compensation and years of service with the Southern Company system for all named executive officers of Georgia Power, Gulf Power and Savannah Electric, except for Messrs. Greer and Willis. Compensation for pension purposes is limited to the average of the highest three of the final 10 years’ compensation. Compensation is base salary plus the excess of annual incentive compensation over 15 percent of base salary. These compensation components are reported under columns titled “Salary” and “Bonus” in the Summary Compensation Tables on pages III-8 through III-10.

		Years of Accredited Service
Remuneration		15		20		25		30		35		40
$	100,000	$	25,500	$	34,000	$	42,500	$	51,000	$	59,500	$	68,000
	300,000		76,500		102,000		127,500		153,000		178,500		204,000
	500,000		127,500		170,000		212,500		255,000		297,500		340,000
	700,000		178,500		238,000		297,500		357,000		416,500		476,000
	900,000		229,500		306,000		382,500		459,000		535,500		612,000
	1,100,000		280,500		374,000		467,500		561,000		654,500		748,000
	1,300,000		331,500		442,000		552,500		663,000		773,500		884,000
	1,500,000		382,500		510,000		637,500		765,000		892,500		1,020,000

     As of December 31, 2005, the applicable compensation levels and years of accredited service for Georgia Power’s, Gulf Power’s and Savannah Electric’s executive officers are presented in the following tables:

Georgia Power

	Compensation		Accredited
Name	Level		Years of Service
Michael D. Garrett	$	1,071,895		37
James H. Miller, III20		550,038		21
William C. Archer		530,649		34
Christopher C. Womack21		500,519		25
Mickey A. Brown		469,242		35
C. B. Harreld22		501,389		32

20	The number of accredited years of service includes 10 years credited to Mr. Miller pursuant to a supplemental pension agreement.
21	The number of accredited years of service includes eight years credited to Mr. Womack pursuant to a supplemental pension agreement.
22	The number of accredited years of service includes 10 years credited to Mr. Harreld pursuant to a deferred compensation agreement.

III-13

Gulf Power

	Compensation		Accredited
Name	Level		Years of Service
Susan N. Story	$	548,779		23
Francis M. Fisher, Jr.		338,949		34
Ronnie R. Labrato		305,820		26
P. Bernard Jacob		270,464		22
Penny M. Manuel		224,814		22
Gene L. Ussery, Jr.		405,889		37

Savannah Electric

	Compensation		Accredited
Name	Level		Years of Service
Anthony R. James	$	440,603		26
W. Craig Barrs		285,876		24
W. Miles Greer23		286,813		29
Kirby R. Willis24		257,532		31

     The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities or computation of Social Security offset that would apply in most cases.

     In 1998, Savannah Electric merged its pension plan into the Southern Company Pension Plan. Savannah Electric also has in effect a supplemental executive retirement plan for certain of its executive employees. The plan is designed to provide participants with a supplemental retirement benefit, which, in conjunction with Social Security and benefits under Southern Company’s qualified pension plan, will equal 70 percent of the highest three of the final 10 years’ average annual earnings (excluding incentive compensation).

     The following table sets forth the estimated combined annual pension benefits under Southern Company’s pension and Savannah Electric’s supplemental executive retirement plans in effect during 2005 which are payable to Messrs. Greer and Willis, upon retirement at the normal retirement age after designated periods of accredited service and at a specified compensation level.

		Years of Accredited Service
Remuneration		15		25		35
$	150,000	$	105,000	$	105,000	$	105,000
	180,000		126,000		126,000		126,000
	210,000		147,000		147,000		147,000
	260,000		182,000		182,000		182,000
	280,000		196,000		196,000		196,000
	300,000		210,000		210,000		210,000
	350,000		245,000		245,000		245,000
	400,000		280,000		280,000		280,000
	430,000		301,000		301,000		301,000
	460,000		322,000		322,000		322,000

23	The number of accredited years of service includes seven years and six months and eight years credited to Mr. Greer under the Southern Company Pension Plan and the Supplemental Executive Retirement Plan, respectively.
24	The number of accredited years of service includes five years and five months granted to Mr. Willis for time served at a non-affiliated electric utility.

III-14

Compensation of Directors.

Standard Arrangements. The following fees are paid to the directors of the respective company for service as a member of the board of directors and any board committee(s), except that employee directors received no fees or compensation for service as a member of the board of directors or any board committee. At the election of the director, all or a portion of the cash retainer may be payable in Southern Company common stock, and all or a portion of the total fees may be deferred under the Deferred Compensation Plan until membership on the board is terminated.

Georgia Power
Annual Cash Retainer Fee	$22,000
Committee Chair Annual Retainer	$3,000
Annual Stock Retainer Fee	520 shares of Southern Company common stock
Meeting Fees	$1,800 for each Board meeting attended,
	$1,200 for each Committee meeting attended and
	$1,200 for each site visit, extra session or conference fee
Gulf Power
Annual Cash Retainer Fee	$12,000
Quarterly Stock Retainer Fee	85 shares of Southern Company common stock
Meeting Fees	$1,200 for each Board meeting attended and
	$1,000 for each Committee meeting attended
Savannah Electric
Annual Cash Retainer Fee	$12,000
Quarterly Stock Retainer Fee	85 shares of Southern Company common stock
Meeting Fees	$1,200 for each Board meeting attended and
	$1,000 for each Committee meeting attended

     Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 2005 in addition to or in lieu of that specified by the standard arrangements specified above.

III-15

Employment Contracts and Termination of Employment and Change in Control Arrangements.

Georgia Power, Gulf Power and Savannah Electric have adopted Southern Company’s Change in Control Program, which is applicable to its officers, and as part of the program, Georgia Power has entered into an individual change in control agreement with its president and chief executive officer and Savannah Electric with Mr. Anthony James, its former president and chief executive officer. If an officer is involuntarily terminated, other than for cause, within two years following a change in control of Southern Company, Georgia Power, Gulf Power and Savannah Electric, the program provides for:

• lump sum payment of two or three times annual compensation,

• up to five years’ coverage under group health and life insurance plans,

• immediate vesting of all stock options, stock appreciation rights and restricted stock previously granted,

• payment of any accrued long-term and short-term bonuses and dividend equivalents and

• payment of any excise tax liability incurred as a result of payments made under any individual agreements.

A change in control of Southern Company is defined under the agreements as:

• acquisition of at least 20 percent of the Southern Company’s stock,

• a change in the majority of the members of the Southern Company’s board of directors in connection with an actual or threatened change in control,

• a merger or other business combination that results in Southern Company’s shareholders immediately before the merger owning less than 65 percent of the voting power after the merger or

• a sale of substantially all the assets of Southern Company.

A change in control of Georgia Power or Gulf Power or Savannah Electric is defined under the agreements as:

• acquisition of at least 50 percent of that Company’s stock,

• a merger or other business combination unless Southern Company controls the surviving entity or

• a sale of substantially all the assets of that Company.

Southern Company also has amended its short- and long-term incentive plan to provide for pro-rata payments at not less than target-level performance if a change in control occurs and the plan is not continued or replaced with a comparable plan or plans.

On May 31, 2002, Southern Company, SCS and Mr. Christopher Womack entered into a Deferred Compensation Agreement which, upon Mr. Womack’s termination, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and Supplemental Executive Retirement Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional eight years. This agreement also contains customary releases and an agreement by Mr. Womack to not engage in specified competitive activities for two years following his retirement.

On May 12, 2003, SCS, Southern Nuclear, Alabama Power and Mr. James Miller entered into an Amended and Restated Supplemental Pension Agreement which, upon Mr. Miller’s termination, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional 10 years.

On September 17, 2003, Georgia Power, SCS, Southern Company and Mr. C. B. Harreld entered into an Amended and Restated Supplemental Pension Agreement which, upon Mr. Harreld’s retirement, will pay him a monthly amount equal to the difference in the amount he receives from the Southern Company Pension Plan and the amount he would have received had he been employed by a subsidiary or an affiliate of Southern Company for an additional 10 years.

III- 16

On January 4, 2006, Georgia Power entered into a separation agreement (the “Separation Agreement”) with William C. Archer, III, an Executive Vice President of the Company, concurrent with his retirement from the Company. Upon Mr. Archer’s termination of employment effective as of March 19, 2006 (the “Separation Date”) and his execution of a release agreement in the form attached to the Separation Agreement (the “Release”), Mr. Archer will be entitled to receive a lump sum payment of $789,400 as soon as practicable following the Separation Date. In the event of a change in control of Georgia Power or Southern Company, Mr. Archer will be entitled to receive the lump sum termination payment under the Separation Agreement as soon as practicable following the change in control.

     In addition, following his retirement, Mr. Archer has agreed to provide certain consulting services to Georgia Power as an independent contractor in accordance with the terms of a consulting agreement (the “Consulting Agreement”). Under the Consulting Agreement, which was executed on January 4, 2006, Mr. Archer will provide professional consulting services as may be requested by Georgia Power and will receive an annual retainer fee of $200,000 to provide such services. In addition, Mr. Archer will be entitled to (i) payment of executive financial planning fees of $6,000 per year during the term of the Consulting Agreement, (ii) reimbursement of reasonable expenses incurred in providing consulting services up to $5,000 per year, and (iii) reimbursement of athletic club membership fees during the term of the Consulting Agreement. The Consulting Agreement will expire March 19, 2009, unless earlier terminated in accordance with its terms. The Consulting Agreement includes confidentiality, non-disclosure and non-interference provisions that apply during the term of the Consulting Agreement and for periods of time following its termination.

Mr. W. Miles Greer and Savannah Electric entered into agreements that will provide for a monthly payment to Mr. Greer after his retirement equal to the difference between the amount he will receive under the Southern Company Pension Plan and Savannah Electric Supplemental Executive Retirement Plan and the amount he would receive under those Plans had he been employed by Savannah Electric an additional seven years and six months under the Pension Plan and an additional eight years under the Supplemental Executive Retirement Plan.

Report on Repricing of Options.

     None.

Compensation Committee Interlocks and Insider Participation.

     None.

III- 17

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners. Southern Company is the beneficial owner of 100% of the outstanding common stock of Georgia Power, Gulf Power and Savannah Electric.

		Amount and
	Name and Address	Nature of		Percent
	of Beneficial	Beneficial		of
Title of Class	Owner	Ownership		Class
Common Stock	The Southern Company				100	%
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	Registrants:
��	Georgia Power		7,761,500
	Gulf Power		992,717
	Savannah Electric		10,844,635

Security Ownership of Management.The following tables show the number of shares of Southern Company common stock owned by the directors, nominees and executive officers as of December 31, 2005. It is based on information furnished by the directors, nominees and executive officers. The shares owned by all directors, nominees and executive officers as a group constitute less than one percent of the total number of shares outstanding on December 31, 2005.

				Shares Beneficially
				Owned Include:
Name of Directors,		Shares		Shares Individuals
Nominees and		Beneficially		Have Rights to Acquire
Executive Officers	Title of Class	Owned (1)		Within 60 days(2)
Georgia Power
Michael D. Garrett	Southern Company Common		99,585		98,116
Gus H. Bell, III	Southern Company Common		1,409
Robert L. Brown	Southern Company Common		4,290
Ronald D. Brown	Southern Company Common		470
Anna R. Cablik	Southern Company Common		2,874
David M. Ratcliffe	Southern Company Common		611,615		596,499
D. Gary Thompson	Southern Company Common		12,992
Richard Ussery	Southern Company Common		28,798
William J. Vereen	Southern Company Common		9,011
E. Jenner Wood, III	Southern Company Common		4,476
William C. Archer	Southern Company Common		140,259		138,851
Mickey A. Brown	Southern Company Common		72,746		59,432
James H. Miller, III	Southern Company Common		134,410		129,445
Christopher C. Womack	Southern Company Common		137,788		136,558
Directors, Nominees and Executive Officers as a group (20 people)	Southern Company Common		1,580,936		1,449,963

III- 18

				Shares Beneficially
				Owned Include:
Name of Directors,		Shares		Shares Individuals
Nominees and		Beneficially		Have Rights to Acquire
Executive Officers	Title of Class	Owned (1)		Within 60 days(2)
Gulf Power
Susan N. Story	Southern Company Common		57,924		53,046
C. LeDon Anchors	Southern Company Common		3,645
William C. Cramer, Jr.	Southern Company Common		3,877
Fred C. Donovan, Sr.	Southern Company Common		2,140
William A. Pullman	Southern Company Common		4,886
Winston E. Scott	Southern Company Common		1,810
Francis M. Fisher, Jr.	Southern Company Common		77,126		73,833
P. Bernard Jacob	Southern Company Common		14,646		11,660
Ronnie R. Labrato	Southern Company Common		41,008		37,563
Penny M. Manuel	Southern Company Common		19,157		18,344
Directors, Nominees and Executive Officers as a group (10 people)	Southern Company Common		226,219		194,446

				Shares Beneficially
				Owned Include:
Name of Directors,		Shares		Shares Individuals
Nominees and		Beneficially		Have Rights to Acquire
Executive Officers	Title of Class	Owned (1)		Within 60 days(2)
Savannah Electric
W. Craig Barrs	Southern Company Common		33,252		27,446
Gus H. Bell, III	Southern Company Common		1,409
Archie H. Davis	Southern Company Common		1,878
Robert B. Miller, III	Southern Company Common		3,310
Arnold M. Tenenbaum	Southern Company Common		2,429
W. Miles Greer	Southern Company Common		45,953		39,219
Kirby R. Willis	Southern Company Common		41,835		36,044
Directors, Nominees and Executive Officers as a group (7 people)	Southern Company Common		130,066		102,709

(1)	As used in the tables, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). For Robert B. Miller, III, this amount includes 1,850 shares held jointly with the estate of Robert B. Miller Jr. and Jean Miller.
(2)	Indicates shares of Southern Company common stock that directors and executive officers have the right to acquire within 60 days.

III-19

Changes in control. Southern Company, Georgia Power, Gulf Power and Savannah Electric know of no arrangements which may at a subsequent date result in any change in control.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

GEORGIA POWER

Transactions with management and others.

Mr. E. Jenner Wood, III is Chairman, President and Chief Executive Officer of SunTrust Bank, Central Group, and Executive Vice President of SunTrust Banks, Inc., Atlanta, Georgia. During 2005, SunTrust Bank, Inc. furnished a number of regular banking services in the ordinary course of business to Georgia Power. Georgia Power intends to maintain normal banking relations with the aforesaid bank in the future.

During 2005, Georgia Power leased a building for $78,375 and purchased uniforms for $173,008 from Riverside Manufacturing Company, and purchased reinforced steel from Anasteel & Supply Company, LLC for $171,142. Mr. William J. Vereen is Chairman, President and Chief Executive Officer of Riverside Manufacturing Company. Ms. Anna R. Cablik is President of Anasteel & Supply Company, LLC.

In 2005, Mr. James Sibert, the husband of Ms. Leslie Sibert, an executive officer of Georgia Power, was employed by Georgia Power as an Engineering Representative and received compensation of $68,536.

Also in 2005, Ms. Linda Holmes, wife of Mr. Richard Holmes, an executive officer of Georgia Power, was employed by Georgia Power as an Accounting Procedures Training Manager and received compensation of $81,819. Mr. Norman Dennis, the son-in-law of Mr. Richard Ussery, a Georgia Power director, was employed by Georgia Power as an Environmental Manager and received compensation of $219,636.

In 2005, Mr. Bradley Braswell, the son-in-law of Mr. Mickey Brown, an executive officer of Georgia Power, was employed by Georgia Power as a Customer Service Supervisor and received compensation of $77,644.

Certain business relationships.

     None.

Indebtedness of management.

     None.

Transactions with promoters.

     None.

GULF POWER

Transactions with management and others.

     None.

Certain business relationships.

     None.

Indebtedness of management.

     None.

Transactions with promoters.

     None.

III- 20

SAVANNAH ELECTRIC

Transactions with management and others.

Mr. Archie Davis is currently President Emeritus and a Director of Savannah Bancorp, Inc. and a Director of The Savannah Bank, N.A., Savannah, Georgia. Mr. Arnold Tenenbaum is Chairman of the Board of Directors of FCB Financial Corp., the holding company of First Chatham Bank. During 2005, these banks furnished a number of regular banking services in the ordinary course of business to Savannah Electric. Savannah Electric intends to maintain normal banking relations with the aforesaid banks in the future.

Certain business relationships.

     None.

Indebtedness of management.

     None.

Transactions with promoters.

     None.

III- 21

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following represents the fees billed to Georgia Power, Gulf Power, Savannah Electric and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company’s principal public accountant for 2005 and 2004:

	2005		2004
	(in thousands)
Georgia Power
Audit Fees (1)	$	3,128	$	2,869
Audit-Related Fees (2)		8		41
Tax Fees		0		0
All Other Fees		0		0
Total	$	3,136	$	2,910
Gulf Power
Audit Fees (1)	$	960	$	897
Audit-Related Fees		0		0
Tax Fees		0		0
All Other Fees		0		0
Total	$	960	$	897
Savannah Electric
Audit Fees (1)	$	660	$	774
Audit-Related Fees		0		0
Tax Fees		0		0
All Other Fees		0		0
Total	$	660	$	774
Southern Power
Audit Fees	$	817	$	648
Audit-Related Fees		0		0
Tax Fees		0		0
All Other Fees		0		0
Total	$	817	$	648

(1)	Includes services performed in connection with financing transactions.
(2)	Includes benefit plan and other non-statutory audit services and accounting consultations in 2005 and 2004.

     The Southern Company Audit Committee (on behalf of Southern Company and all its subsidiaries) adopted a Policy of Engagement of the Independent Auditor for Audit and Non-Audit Services that includes requirements for such Audit Committee to pre-approve audit and non-audit services provided by Deloitte & Touche LLP. All of the audit services provided by Deloitte & Touche LLP in fiscal years 2005 and 2004 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.

III- 22

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report on this Form 10-K:

(1)	Financial Statements:
	Report of Independent Registered Public Accounting Firm on Internal Control over Financial Statements for Southern Company and Subsidiary Companies is listed under Item 8 herein.
	Reports of Independent Registered Public Accounting Firm on the financial statements for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed under Item 8 herein.
	The financial statements filed as a part of this report for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed under Item 8 herein.

(2)	Financial Statement Schedules:
	Reports of Independent Registered Public Accounting Firm as to Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are included herein on pages IV-9, IV-10, IV-11, IV-12, IV-13, IV-14 and IV-15.
	Financial Statement Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed in the Index to the Financial Statement Schedules at page S-1.

(3)	Exhibits:
	Exhibits for Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and Southern Power are listed in the Exhibit Index at page E-1.

IV-1

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

THE SOUTHERN COMPANY
By:		David M. Ratcliffe
		Chairman, President and
		Chief Executive Officer
By:		/s/ Wayne Boston
		(Wayne Boston, Attorney-in-fact)
Date:	February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

David M. Ratcliffe
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)

Thomas A. Fanning
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)

W. Dean Hudson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)

               Directors:

Juanita P. Baranco       Zack T. Pate
Dorrit J. Bern                J. Neal Purcell
Francis S. Blake            William G. Smith, Jr.
Thomas F. Chapman     Gerald J. St. Pe’
Donald M. James

By:   /s/ Wayne Boston

(Wayne Boston, Attorney-in-fact)

Date: February 27, 2006

IV-2

ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ALABAMA POWER COMPANY
By:		Charles D. McCrary
		President and Chief Executive Officer
By:		/s/ Wayne Boston
		(Wayne Boston, Attorney-in-fact)
Date:	February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Charles D. McCrary
President, Chief Executive Officer and Director
(Principal Executive Officer)

Art P. Beattie
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)

Philip C. Raymond
Vice President and Comptroller
(Principal Accounting Officer)

               Directors:

Whit Armstrong	Malcolm Portera
David J. Cooper, Sr.	Robert D. Powers
R. Kent Henslee	David M. Ratcliffe
John D. Johns	C. Dowd Ritter
Carl E. Jones, Jr.	James H. Sanford
Patricia M. King	John Cox Webb, IV
Wallace D. Malone, Jr.	James W. Wright

   By:      /s/ Wayne Boston

(Wayne Boston, Attorney-in-fact)

   Date: February 27, 2006

IV-3

GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

GEORGIA POWER COMPANY
By:	Michael D. Garrett
	President and Chief Executive Officer
By:	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)
Date:	February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Michael D. Garrett
President, Chief Executive Officer and Director
(Principal Executive Officer)

Cliff S. Thrasher
Executive Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)

W. Ron Hinson
Vice President, Comptroller and Chief Accounting Officer
(Principal Accounting Officer)

               Directors:

Robert L. Brown, Jr.       D. Gary Thompson
Ronald D. Brown            Richard W. Ussery
Anna R. Cablik               William Jerry Vereen
David M. Ratcliffe          E. Jenner Wood, III

        By:    /s/ Wayne Boston

  (Wayne Boston, Attorney-in-fact)

        Date: February 27, 2006

IV-4

GULF POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

GULF POWER COMPANY
By:	Susan N. Story
	President and Chief Executive Officer
By:	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)
Date:February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Susan N. Story
President, Chief Executive Officer and Director
(Principal Executive Officer)

Ronnie R. Labrato
Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

               Directors:

C. LeDon Anchors                 William A. Pullum
William C. Cramer, Jr.           Winston E. Scott
Fred C. Donovan, Sr.

        By:   /s/ Wayne Boston

                (Wayne Boston, Attorney-in-fact)

        Date: February 27, 2006

IV-5

MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

MISSISSIPPI POWER COMPANY
By:	Anthony J. Topazi
	President and Chief Executive Officer
By:	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)
Date:February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Anthony J. Topazi
President, Chief Executive Officer and Director
(Principal Executive Officer)

Frances V. Turnage
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)

Moses H. Feagin
Comptroller
(Principal Accounting Officer)

               Directors:

Tommy E. Dulaney          Aubrey B. Patterson, Jr.
Warren A. Hood, Jr.         George A. Schloegel
Robert C. Khayat             Philip J. Terrell

By:	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)
Date:February 27, 2006

IV-6

SAVANNAH ELECTRIC AND POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

W. Craig Barrs
President, Chief Executive Officer and Director
(Principal Executive Officer)

Kirby R. Willis
Vice President, Treasurer, Chief Financial
Officer and Assistant Corporate Secretary
(Principal Financial and Accounting Officer)

               Directors:

Gus H. Bell, III            Robert B. Miller, III
Archie H. Davis            Arnold M. Tenenbaum

By:		/s/ Wayne Boston
		(Wayne Boston, Attorney-in-fact)
Date:	February 27, 2006

IV-7

SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

SOUTHERN POWER COMPANY
By:	Ronnie L. Bates
	President and Chief Executive Officer
By:	/s/ Wayne Boston
	(Wayne Boston, Attorney-in-fact)
Date:February 27, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Ronnie L. Bates
President, Chief Executive Officer and Director
(Principal Executive Officer)

Michael W. Southern
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

               Directors:

William P. Bowers            W. Dean Hudson
Thomas A. Fanning            David M. Ratcliffe

By:		/s/ Wayne Boston
		(Wayne Boston, Attorney-in-fact)
Date:	February 27, 2006

IV-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Southern Company

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

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-9

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Alabama Power Company:

We have audited the financial statements of Alabama Power Company (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-3) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Birmingham, Alabama
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-10

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Georgia Power Company:

We have audited the financial statements of Georgia Power Company (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-4) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-11

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Gulf Power Company:

We have audited the financial statements of Gulf Power Company (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-5) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Mississippi Power Company:

We have audited the financial statements of Mississippi Power Company (the “Company”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated February 27, 2006; such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (page S-6) listed in the accompanying index at Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-13

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Savannah Electric and Power Company:

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

/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-14

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southern Power Company:

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

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 27, 2006

Member of

Deloitte Touche Tohmatsu

IV-15

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule		Page
II	Valuation and Qualifying Accounts and Reserves 2005, 2004 and 2003
	The Southern Company and Subsidiary Companies		S-2
	Alabama Power Company		S-3
	Georgia Power Company		S-4
	Gulf Power Company		S-5
	Mississippi Power Company		S-6
	Savannah Electric and Power Company		S-7
	Southern Power Company and Subsidiary Companies		S-8

     Schedules I through V not listed above are omitted as not applicable or not required. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.

S-1

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other					Balance at End
Description	of Period		Income		Accounts		Deductions			of Period
Provision for uncollectible accounts (a)
2005	$	33,399	$	46,193	$	24	$	42,106	(b)	$	37,510
2004		15,812		54,248		2		36,663	(b)		33,399
2003		19,015		37,491		1,386		42,080	(b)		15,812

(a)	Excludes provisions for uncollectible accounts in all periods for Southern Company Gas — a discontinued operation.
(b)	Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-2

ALABAMA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other			Balance at End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2005	$	5,404	$	12,832	$	—	$10,676 (Note)	$	7,560
2004		4,756		10,346		—	9,698 (Note)		5,404
2003		4,827		13,444		—	13,515 (Note)		4,756

Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-3

GEORGIA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other			Balance at End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2005	$	7,100	$	24,145	$	—	$22,598 (Note)	$	8,647
2004		5,350		20,461		—	18,711 (Note)		7,100
2003		5,825		15,577		—	16,052 (Note)		5,350

Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-4

GULF POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other			Balance at End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2005	$	2,144	$	1,275	$	—	$2,285 (Note)	$	1,134
2004		947		2,851		—	1,654 (Note)		2,144
2003		889		2,122		—	2,064 (Note)		947

Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-5

MISSISSIPPI POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other				Balance at End
Description	of Period		Income		Accounts		Deductions		of Period
Provision for uncollectible accounts
2005	$	774	$	2,610	$	—	$1,063 (Note)		$	2,321
2004		897		1,338		—	1,461 (Note)			774
2003		718		1,947		135	1,903 (Note)	��		897

Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-6

SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other			Balance at End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2005	$	878	$	1,449	$	—	$1,411 (Note)	$	916
2004		817		930		—	869 (Note)		878
2003		902		828		—	913 (Note)		817

Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.

S-7

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Stated in Thousands of Dollars)

			Additions
	Balance at Beginning		Charged to		Charged to Other			Balance at End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2005	$	350	$	—	$	—	$350 (Note)	$	—
2004		350		—		—	—		350
2003		350		—		—	—		350

Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.

S-8

EXHIBIT INDEX

     The following exhibits indicated by an asterisk (*) preceding the exhibit number are filed herewith. The balance of the exhibits has heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements required to be identified as such by Item 15 of Form 10-K.

(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

       Savannah Electric

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

(3) Articles of Incorporation and By-Laws

       Southern Company

(a) 1	-	Composite Certificate of Incorporation of Southern Company, reflecting all amendments thereto through January 5, 1994. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A and in Certificate of Notification, File No. 70-8181, as Exhibit A.)
(a) 2	-	By-laws of Southern Company as amended effective February 17, 2003, and as presently in effect. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 3(a)1.)

     Alabama Power

(b) 1	-	Charter of Alabama Power and amendments thereto through February 17, 2004. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in Alabama Power’s Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4, in Alabama Power’s Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2, in Alabama Power’s Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4, in Alabama Power’s Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)1 and in Form 8-K dated February 5, 2004, File No. 1-3164 as Exhibit 4.4.)
(b) 2	-	By-laws of Alabama Power as amended effective April 25, 2003, and as presently in effect. (Designated in Alabama Power’s Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)2.)

E-1

     Georgia Power

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

     Gulf Power

(d) 1	-	Amended and Restated Articles of Incorporation of Gulf Power and amendments thereto through November 16, 2005. (Designated in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 3.1 and in Form 8-K dated November 9, 2005, File No. 0-2429, as Exhibit 4.7.)
(d) 2	-	By-laws of Gulf Power as amended effective November 2, 2005, and as presently in effect. (Designated in Form 8-K dated November 2, 2005, File No. 0-2429, as Exhibit 3.2.)

     Mississippi Power

(e) 1 - Articles of Incorporation of Mississippi Power, articles of merger of Mississippi Power Company (a Maine corporation) into Mississippi Power and articles of amendment to the articles of incorporation of Mississippi Power through April 2, 2004. (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No. 0-6849, as Exhibit 4(b)-3, in Mississippi Power’s Form 10-K for the year ended December 31, 1997, File No. 0-6849, as Exhibit 3(e)2, in Mississippi Power’s Form 10-K for the year ended December 31, 2000, File No. 0-6849, as Exhibit 3(e)2 and in Mississippi Power’s Form 8-K dated March 3, 2004, File No. 0-6849, as Exhibit 4.6.)

E-2

(e) 2 - By-laws of Mississippi Power as amended effective February 28, 2001, and as presently in effect. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2001, File No. 0-6849, as Exhibit 3(e)2.)

     Savannah Electric

(f) 1	-	Charter of Savannah Electric and amendments thereto through June 10, 2004. (Designated in Registration Nos. 33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in Form 8-K dated November 9, 1993, File No. 1-5072, as Exhibit 4(b) in Savannah Electric’s Form 10-K for the year ended December 31, 1998, as Exhibit 3(f)2 and in Form 8-K dated May 27, 2004, File No. 1-5072, as Exhibits 4.6 and 4.7.)
(f) 2	-	By-laws of Savannah Electric as amended effective May 17, 2000, and as presently in effect. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072, as Exhibit 3(f)2.)

     Southern Power

(g) 1	-	Certificate of Incorporation of Southern Power dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)
(g) 2	-	By-laws of Southern Power effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)

(4) Instruments Describing Rights of Security Holders, Including Indentures

     Southern Company

(a) 1	-	Subordinated Note Indenture dated as of February 1, 1997, among Southern Company, Southern Company Capital Funding, Inc. and Bank of New York Trust Company, N.A., as Successor Trustee, and indentures supplemental thereto dated as of February 4, 1997. (Designated in Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and 333-28355 as Exhibit 4.2.)
(a) 2	-	Subordinated Note Indenture dated as of June 1, 1997, among Southern Company, Southern Company Capital Funding, Inc. and Bank of New York Trust Company, N.A., as Successor Trustee, and indentures supplemental thereto through July 31, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 1997, File No. 1-3526, as Exhibit 4(a)2, in Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated December 18, 1998, File No. 1-3526, as Exhibit 4.4 and in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.4.)
(a) 3	-	Senior Note Indenture dated as of February 1, 2002, among Southern Company, Southern Company Capital Funding, Inc. and The Bank of New York, as Trustee, and indentures supplemental thereto through November 16, 2005. (Designated in Form 8-K dated January 29, 2002, File No. 1-3526, as Exhibits 4.1 and 4.2, in

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		Form 8-K dated January 30, 2002, File No. 1-3526, as Exhibit 4.2 and in Form 8-K dated November 8, 2005, File No. 1-3526, as Exhibit 4.2.)
(a) 4	-	Amended and Restated Trust Agreement of Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.6.)
(a) 5	-	Amended and Restated Trust Agreement of Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.6.)
(a) 6	-	Amended and Restated Trust Agreement of Southern Company Capital Trust VI dated as of July 1, 2002. (Designated in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.7-A.)
(a) 7	-	Capital Securities Guarantee Agreement relating to Southern Company Capital Trust I dated as of February 1, 1997. (Designated in Registration No. 333-28349 as Exhibit 4.10.)
(a) 8	-	Capital Securities Guarantee Agreement relating to Southern Company Capital Trust II dated as of February 1, 1997. (Designated in Registration No. 333-28355 as Exhibit 4.10.)
(a) 9	-	Preferred Securities Guarantee Agreement relating to Southern Company Capital Trust VI dated as of July 1, 2002. (Designated in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.11-A.)

     Alabama Power

(b) 1 - Indenture dated as of January 1, 1942, between Alabama Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 1, 1994. (Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2, 2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in Alabama Power’s Form 10-K for the year ended December 31, 1990, File No. 1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated February 17, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993, File No. 1-3164, as Exhibit 4, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(b), in Certificate of Notification, File No. 70-8069, as Exhibits A and B, in Certificate of Notification, File No. 70-8069, as Exhibit A, in Certificate of Notification, File No. 70-8069, as Exhibit A and in Form 8-K dated November 30, 1994, File No. 1-3164, as Exhibit 4.)

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(b) 2	-	Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through October 2, 2002. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K dated February 18, 1999, File No. 3164, as Exhibit 4.2 and in Form 8-K dated September 26, 2002, File No. 3164, as Exhibits 4.9-A and 4.9-B.)
(b) 3	-	Senior Note Indenture dated as of December 1, 1997, between Alabama Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through February 8, 2006. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 11, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 13, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11, 2000, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated June 21, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated October 16, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated November 20, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated December 6, 2002, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 11, 2003, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 12, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 15, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 1, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 10, 2004, File No. 1-3164, as Exhibit 4.2 in Form 8-K dated April 7, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 19, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 9, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated March 8, 2005, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 11, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 13, 2006, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated February 1, 2006, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b).)
(b) 4	-	Amended and Restated Trust Agreement of Alabama Power Capital Trust IV dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.12-A.)
(b) 5	-	Amended and Restated Trust Agreement of Alabama Power Capital Trust V dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.12-B.)
(b) 6	-	Guarantee Agreement relating to Alabama Power Capital Trust IV dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.16-A.)

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(b) 7 - Guarantee Agreement relating to Alabama Power Capital Trust V dated as of September 1, 2002. (Designated in Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit 4.16-B.)

     Georgia Power

(c) 1	-	Subordinated Note Indenture dated as of June 1, 1997, between Georgia Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 23, 2004. (Designated in Certificate of Notification, File No. 70-8461, as Exhibits D and E, in Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit 4.4, in Form 8-K dated June 13, 2002, File No. 1-6468, as Exhibit 4.4, in Form 8-K dated October 30, 2002, File No. 1-6468, as Exhibit 4.4 and in Form 8-K dated January 15, 2004, File No. 1-6468, as Exhibit 4.4.
(c) 2	-	Senior Note Indenture dated as of January 1, 1998, between Georgia Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 6, 2005. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated February 15, 2000, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated January 26, 2001, File No. 1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 16, 2001, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 27, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 15, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 13, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 21, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated April 10, 2003, File No. 1-6468, as Exhibits 4.1, 4.2 and 4.3, in Form 8-K dated September 8, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated September 23, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated January 12, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2, in Form 8-K dated February 12, 2004, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated August 11, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2, in Form 8-K dated January 13, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated April 12, 2005, File No. 1-6468, as Exhibit 4.1 and in Form 8-K dated November 30, 2005, File No. 1-6468, as Exhibit 4.1.)
(c) 3	-	Amended and Restated Trust Agreement of Georgia Power Capital Trust V dated as of June 1, 2002. (Designated in Form 8-K dated June 13, 2002, as Exhibit 4.7-A.)
(c) 4	-	Amended and Restated Trust Agreement of Georgia Power Capital Trust VI dated as of November 1, 2002. (Designated in Form 8-K dated October 30, 2002, as Exhibit 4.7-A.)
(c) 5	-	Amended and Restated Trust Agreement of Georgia Power Capital Trust VII dated as of January 1, 2004. (Designated in Form 8-K dated January 15, 2004, as Exhibit 4.7-A.)

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(c) 6	-	Guarantee Agreement relating to Georgia Power Capital Trust V dated as of June 1, 2002. (Designated in Form 8-K dated June 13, 2002, as Exhibit 4.11-A.)
(c) 7	-	Guarantee Agreement relating to Georgia Power Capital Trust VI dated as of November 1, 2002. (Designated in Form 8-K dated October 30, 2002, as Exhibit 4.11-A.)
(c) 8	-	Guarantee Agreement relating to Georgia Power Capital Trust VII dated as of January 1, 2004. (Designated in Form 8-K dated January 15, 2004, as Exhibit 4.11-A.)

     Gulf Power

(d) 1	-	Indenture dated as of September 1, 1941, between Gulf Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through November 1, 1996. (Designated in Registration Nos. 2-4833 as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in Gulf Power’s Form 10-K for the year ended December 31, 1991, File No. 0-2429, as Exhibit 4(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165 as Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibits E and F, in Form 8-K dated January 17, 1996, File No. 0-2429, as Exhibit 4, in Certificate of Notification, File No. 70-8229, as Exhibit A, in Certificate of Notification, File No. 70-8229, as Exhibit A and in Form 8-K dated November 6, 1996, File No. 0-2429, as Exhibit 4.)
(d) 2	-	Subordinated Note Indenture dated as of January 1, 1997, between Gulf Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through December 13, 2002. (Designated in Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.2 and in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.2.)
(d) 3	-	Senior Note Indenture dated as of January 1, 1998, between Gulf Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through August 30, 2005. (Designated in Form 8-K dated June 17, 1998, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 18, 2002, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated March 21, 2003, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 10, 2003, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated September 5, 2003, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated April 6, 2004, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated September 13, 2004, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated August 11, 2005, File No. 0-2429, as Exhibit 4.1 and in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 4.1.)

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(d) 4	-	Amended and Restated Trust Agreement of Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)
(d) 5	-	Amended and Restated Trust Agreement of Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.5.)
(d) 6	-	Guarantee Agreement relating to Gulf Power Capital Trust III dated as of November 1, 2001. (Designated in Form 8-K dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)
(d) 7	-	Guarantee Agreement relating to Gulf Power Capital Trust IV dated as of December 1, 2002. (Designated in Form 8-K dated December 5, 2002, File No. 0-2429, as Exhibit 4.8.)

     Mississippi Power

(e) 1	-	Indenture dated as of September 1, 1941, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Successor Trustee, and indentures supplemental thereto through June 30, 2005. (Designated in Registration Nos. 2-4834 as Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2, 2-71537 as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2), 33-39833 as Exhibit 4(a)-2, in Mississippi Power’s Form 10-K for the year ended December 31, 1991, File No. 0-6849, as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibit 4(a)-2, in Second Certificate of Notification, File No. 70-7941, as Exhibit I, in Mississippi Power’s Form 8-K dated February 26, 1993, File No. 0-6849, as Exhibit 4(a)-2, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File No. 0-6849, as Exhibit 1, in Certificate of Notification, File No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994, File No. 0-6849, as Exhibit 4, in Certificate of Notification, File No. 70-8127, as Exhibit C, in Form 8-K dated December 5, 1995, File No. 0-6849, as Exhibit 4 and in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.16.)
(e) 2	-	Senior Note Indenture dated as of May 1, 1998 between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indentures supplemental thereto through June 30, 2005. (Designated in Form 8-K dated May 14, 1998, File No. 0-6849, as Exhibits 4.1, 4.2(a) and 4.2(b), in Form 8-K dated March 22, 2000, File No. 0-6849, as Exhibit 4.2, in Form 8-K dated March 12, 2002, File No. 0-6849, as Exhibit 4.2, in Form 8-K dated April 24, 2003, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated March 3, 2004, File No. 001-11229, as Exhibit 4.2 and in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.2.)
(e) 3	-	Subordinated Note Indenture dated as of February 1, 1997, between Mississippi Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee, and indenture supplemental thereto dated as of March 22, 2002. (Designated in Form 8-K dated February 20, 1997, File No. 0-6849, as

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		Exhibits 4.1 and 4.2 and in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
(e) 4	-	Amended and Restated Trust Agreement of Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
(e) 5	-	Guarantee Agreement relating to Mississippi Power Capital Trust II dated as of March 1, 2002. (Designated in Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit 4.8.)

     Savannah Electric

(f) 1	-	Indenture dated as of March 1, 1945, between Savannah Electric and The Bank of New York, as Trustee, and indentures supplemental thereto through May 1, 1996. (Designated in Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in Savannah Electric’s Form 10-K for the year ended December 31, 1991, File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 23, 1996, File No. 1-5072, as Exhibit 4.)
(f) 2	-	Senior Note Indenture dated as of March 1, 1998 between Savannah Electric and The Bank of New York, as Trustee, and indentures supplemental thereto through December 9, 2004. (Designated in Form 8-K dated March 9, 1998, File No. 1-5072, as Exhibits 4.1 and 4.2, in Form 8-K dated May 8, 2001, File No. 1-5072, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 4, 2002, File No. 1-5072, as Exhibit 4.2, in Form 8-K dated November 4, 2002, File No. 1-5072, as Exhibit 4.2, in Form 8-K dated December 10, 2003, File No. 1-5072, as Exhibits 4.1 and 4.2 and in Form 8-K dated December 2, 2004, File No. 1-5072, as Exhibit 4.1.)
(f) 3	-	Subordinated Note Indenture dated as of December 1, 1998, between Savannah Electric and The Bank of New York, as Trustee, and indenture supplemental thereto dated as of December 9, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.3 and 4.4.)
(f) 4	-	Amended and Restated Trust Agreement of Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.7.)
(f) 5	-	Guarantee Agreement relating to Savannah Electric Capital Trust I dated as of December 1, 1998. (Designated in Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.)

     Southern Power

(g) 1 - Indenture dated as of June 1, 2002, between Southern Power and The Bank of New York, as Trustee, and indentures supplemental thereto through July 8, 2003. (Designated in Registration No. 333-98553 as Exhibits 4.1 and 4.2 and in Southern

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Power’s Form 10-Q for the quarter ended June 30, 2003, File No. 333-98553, as Exhibit 4(g)1.)

(10) Material Contracts

       Southern Company

#		(a)	1	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. (Designated in Form S-8, File No. 333-73462, as Exhibit 4(c).)
#	*	(a)	2	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan.
#	*	(a)	3	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries.
#		(a)	4	-	Deferred Compensation Plan for Directors of The Southern Company, Amended and Restated effective February 19, 2001. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.)
#		(a)	5	-	Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)1.)
#		(a)	6	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)2.)
#		(a)	7	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)62.)
#		(a)	8	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)64 and in Southern Company’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)3.)
#		(a)	9	-	Amended and Restated Change in Control Agreement between Southern Company, SCS and G. Edison Holland, Jr. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2004, File No. 1-3526, as Exhibit 10(a)13.)
#		(a)	10	-	Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and Charles D. McCrary, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)5.)

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#		(a)	11	-	Amended and Restated Change in Control Agreement between Southern Company, SCS and David M. Ratcliffe, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)3.)
#		(a)	12	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)105.)
#	*	(a)	13	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy.
#		(a)	14	-	Master Separation and Distribution Agreement dated as of September 1, 2000 between Southern Company and Mirant. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)100.)
#		(a)	15	-	Indemnification and Insurance Matters Agreement dated as of September 1, 2000 between Southern Company and Mirant. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.)
#		(a)	16	-	Tax Indemnification Agreement dated as of September 1, 2000 among Southern Company and its affiliated companies and Mirant and its affiliated companies. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)102.)
#		(a)	17	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103.)
#		(a)	18	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)104.)
#		(a)	19	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)92.)
#		(a)	20	-	Amended and Restated Change in Control Agreement between Southern Company, SCS and Thomas A. Fanning, effective June 1, 2004. (Designated in Southern

E-11

					Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)4.)
#		(a)	21	-	Supplemental Pension Agreement between Savannah Electric, Gulf Power, SCS and G. Edison Holland, Jr. effective February 22, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)119.)
#		(a)	22	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)3.)
#		(a)	23	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 10(a)(2).)
#		(a)	24	-	Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and Michael D. Garrett, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)6.)
#	*	(a)	25	-	Base Salaries of Named Executive Officers.
#		(a)	26	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2004, File No. 1-3526, as Exhibit 10(a)30.)

     Alabama Power

		(b)	1	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)6.)
#		(b)	2	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
#	*	(b)	3	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	*	(b)	4	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)3 herein.
#		(b)	5	-	Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
#		(b)	6	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.

E-12

#		(b)	7	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
#		(b)	8	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
#		(b)	9	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
#		(b)	10	-	Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated effective January 1, 2001. (Designated in Alabama Power’s Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 10(b)28.)
#		(b)	11	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
#	*	(b)	12	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
#		(b)	13	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)17 herein.
#		(b)	14	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)18 herein.
#		(b)	15	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)19 herein.
#		(b)	16	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
#		(b)	17	-	Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and Charles D. McCrary. See Exhibit 10(a)14 herein.
#		(b)	18	-	Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and C. Alan Martin, effective June 1, 2004. (Designated in Alabama Power’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(b)4.)
#	*	(b)	19	-	Base Salaries of Named Executive Officers.

E-13

# (b) 20 - Summary of Non-Employee Director Compensation Arrangements. (Designated in Alabama Power’s Form 10-K for the year ended December 31, 2004, File No. 1-3164, as Exhibit 10(b)20.)

     Georgia Power

		(c)	1	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
		(c)	2	-	Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between Georgia Power and OPC. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
		(c)	3	-	Revised and Restated Integrated Transmission System Agreement between Georgia Power and Dalton dated as of December 7, 1990. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)
		(c)	4	-	Revised and Restated Integrated Transmission System Agreement between Georgia Power and MEAG dated as of December 7, 1990. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)
#		(c)	5	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
#	*	(c)	6	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	*	(c)	7	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)3 herein.
#		(c)	8	-	Southern Company Deferred Compensation Plan as amended and restated effective January 1, 2004. See Exhibit 10(a)5 herein.
#		(c)	9	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
#		(c)	10	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
#		(c)	11	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
#		(c)	12	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.

E-14

#		(c)	13	-	Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective January 13, 2003. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 2002, File No. 1-6468, as Exhibit 10(c)68.)
#		(c)	14	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
#	*	(c)	15	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
#		(c)	16	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)17 herein.
#		(c)	17	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)18 herein.
#		(c)	18	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)19 herein.
#		(c)	19	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
#		(c)	20	-	Deferred Compensation Agreement between Southern Company, SCS and Christopher C. Womack dated May 31, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)118.)
#		(c)	21	-	Amended and Restated Supplemental Pension Agreement among SCS, Southern Nuclear, Alabama Power and James H. Miller, III. (Designated in Alabama Power’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3164, as Exhibit 10(b)1.)
#		(c)	22	-	Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and Michael D. Garrett. See Exhibit 10(a)24 herein.
#		(c)	23	-	Separation Agreement, dated as of January 4, 2006, between Georgia Power and William C. Archer III. (Designated in Form 8-K dated January 4, 2006, File No. 1-6468, as Exhibit 10.1.)
#		(c)	24	-	Consulting Agreement, dated as of January 4, 2006, between Georgia Power and William C. Archer III. (Designated in Form 8-K dated January 4, 2006, File No. 1-6468, as Exhibit 10.2.)

E-15

#	*	(c)	25	-	Base Salaries of Named Executive Officers.
#		(c)	26	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Georgia Power’s Form 10-K for the year ended December 31, 2004, File No. 1-6468, as Exhibit 10(c)24.)

     Gulf Power

		(d)	1	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
		(d)	2	-	Unit Power Sales Agreement dated July 19, 1988, between FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
		(d)	3	-	Amended Unit Power Sales Agreement dated July 20, 1988, between FP&L and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(e).)
		(d)	4	-	Amended Unit Power Sales Agreement dated August 17, 1988, between JEA and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric and SCS. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 1988, File No. 1-5072, as Exhibit 10(f).)
#		(d)	5	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
#	*	(d)	6	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	*	(d)	7	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)3 herein.
#		(d)	8	-	Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
#		(d)	9	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
#		(d)	10	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
#		(d)	11	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)22 herein.

E-16

#		(d)	12	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
#		(d)	13	-	Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated effective January 1, 2000 and First Amendment thereto. (Designated in Gulf Power’s Form 10-K for the year ended December 31, 2000, File No. 0-2429 as Exhibit 10(d)33.)
#		(d)	14	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
#	*	(d)	15	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
#		(d)	16	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)17 herein.
#		(d)	17	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)18 herein.
#		(d)	18	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)19 herein.
#		(d)	19	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
#	*	(d)	20	-	Base Salaries of Named Executive Officers.
#		(d)	21	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Gulf Power’s Form 10-K for the year ended December 31, 2004, File No. 0-2429, as Exhibit 10(d)20.)
Mississippi Power
		(e)	1	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
		(e)	2	-	Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 1981, File No.

E-17

					0-6849, as Exhibit 10(f), in Mississippi Power’s Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2) and in Mississippi Power’s Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
#		(e)	3	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
#	*	(e)	4	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	*	(e)	5	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)3 herein.
#		(e)	6	-	Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
#		(e)	7	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
#		(e)	8	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
#		(e)	9	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
#		(e)	10	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
#		(e)	11	-	Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated effective January 1, 2000 and Amendment Number One thereto. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 1999, File No. 0-6849 as Exhibit 10(e)37 and in Mississippi Power’s Form 10-K for the year December 31, 2000, File No. 0-6849 as Exhibit 10(e)30.)
#		(e)	12	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
#	*	(e)	13	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
#		(e)	14	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)17 herein.

E-18

#		(e)	15	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)18 herein.
#		(e)	16	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)19 herein.
#		(e)	17	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
#	*	(e)	18	-	Base Salaries of Named Executive Officers.
#		(e)	19	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2004, File No. 001-11229, as Exhibit 10(e)20.)
		(e)	20	-	Credit Agreement, dated as of October 20, 2005, by and among Mississippi Power and the lenders named therein. (Designated in Form 8-K dated October 20, 2005, File No. 001-11229, as Exhibit 10.1.)

Savannah Electric

		(f)	1	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
#		(f)	2	-	Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
#	*	(f)	3	-	First Amendment effective January 1, 2005 to the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	*	(f)	4	-	Forms of Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)3 herein.
#		(f)	5	-	Supplemental Executive Retirement Plan of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)13.)
#		(f)	6	-	Deferred Compensation Plan for Key Employees of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.)

E-19

#		(f)	7	-	1997 Deferred Compensation Plan for Directors of Savannah Electric, Amended and Restated effective October 26, 2000. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)18.)
#		(f)	8	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)6 herein.
#		(f)	9	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)8 herein.
#		(f)	10	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)23 herein.
#		(f)	11	-	Southern Company Deferred Compensation Plan, as amended and restated January 1, 2004. See Exhibit 10(a)5 herein.
#		(f)	12	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)7 herein.
#		(f)	13	-	Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)12 herein.
#	*	(f)	14	-	First Amendment effective November 18, 2005 and Second Amendment effective December 27, 2005 to the Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy. See Exhibit 10(a)13 herein.
#		(f)	15	-	Agreement for supplemental pension benefits between Savannah Electric and William Miles Greer. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)34.)
#		(f)	16	-	Agreement crediting additional service between Savannah Electric and William Miles Greer. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)35.)
#		(f)	17	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Communications, Energy Solutions and Southern Nuclear. See Exhibit 10(a)17 herein.
#		(f)	18	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)18 herein.
#		(f)	19	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric. See Exhibit 10(a)19 herein.

E-20

#		(f)	20	-	Change in Control Agreement between Southern Company, Savannah Electric and Anthony R. James. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2002, File No. 1-3526, as Exhibit 10(a)113.)
#		(f)	21	-	Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)22 herein.
#		(f)	22	-	Savannah Electric and Power Company Change in Control Plan Benefit Determination Policy, effective October 26, 2000. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2003, File No. 1-5072, as Exhibit 10(f)34.)
#	*	(f)	23	-	Base Salaries of Named Executive Officers.
#		(f)	24	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2004, File No. 1-5072, as Exhibit 10(f)23.)

Southern Power

(g)	1	-	Service contract dated as of January 1, 2001, between SCS and Southern Power. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)(2).)
(g)	2	-	Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
(g)	3	-	Amended and Restated Operating Agreement between Southern Power and Alabama Power effective December 1, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 10(a)61.)
(g)	4	-	Amended and Restated Operating Agreement between Southern Power and Georgia Power effective December 1, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 10(a)62.)
(g)	5	-	Power Purchase Agreement between Southern Power and Alabama Power dated as of June 1, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.18.)
(g)	6	-	Amended and Restated Power Purchase Agreement between Southern Power and Georgia Power at Plant Autaugaville dated as of August 6, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.19.)
(g)	7	-	Contract for the Purchase of Firm Capacity and Energy between Southern Power and Georgia Power dated as of July 26, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.21.)

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	(g)	8	-	Power Purchase Agreement between Southern Power and Georgia Power at Plant Goat Rock dated as of March 30, 2001. (Designated in Registration No. 333-98553 as Exhibit 10.22.)
	(g)	9	-	Multi-Year Credit Agreement among Southern Power, Citibank N.A., as the administrative agent, and the lenders listed therein dated as of June 10, 2005. (Designated in Southern Power’s Form 10-Q for the quarter ended June 30, 2005, File No. 333-98553 as Exhibit 10(g)1.)
	(g)	10	-	Purchase and Sale Agreement, by and between CP Oleander, LP and CP Oleander I, Inc., as Sellers, Constellation Power, Inc. and SP Newco I LLC and SP Newco II LLC, as Purchasers, and Southern Power, as Purchaser’s Parent, for the Sale of Partnership Interests of Oleander Power Project, LP, dated as of April 8, 2005. (Designated in Form 8-K dated June 7, 2005, File No. 333-98553, as Exhibit 2.1 and incorporated herein by reference.)
*	(g)	11	-	Cooperative Agreement between United States Department of Energy and Southern Company Services, Inc. dated as of February 22, 2006. (Southern Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the Securities and Exchange Commission. Southern Power has omitted such portions from this filing and filed them separately with the Securities and Exchange Commission.)

(14) Code of Ethics

        Southern Company

(a) - The Southern Company Code of Ethics. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 14(a).)

     Alabama Power

(b) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

     Georgia Power

(c) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

     Gulf Power

(d) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

     Mississippi Power

(e) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

     Savannah Electric

(f) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

     Southern Power

(g) - The Southern Company Code of Ethics. See Exhibit 14(a) herein.

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(21) Subsidiaries of Registrants

       Southern Company

* (a) - Subsidiaries of Registrant.

     Alabama Power

(b) - Subsidiaries of Registrant. See Exhibit 21(a) herein.

     Georgia Power

(c) - Subsidiaries of Registrant. See Exhibit 21(a) herein.

     Gulf Power

(d) - Subsidiaries of Registrant. See Exhibit 21(a) herein.

     Mississippi Power

(e) - Subsidiaries of Registrant. See Exhibit 21(a) herein.

     Savannah Electric

(f) - Subsidiaries of Registrant. See Exhibit 21(a) herein.

     Southern Power

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

(23) Consents of Experts and Counsel

        Southern Company

* (a) 1 - Consent of Deloitte & Touche LLP.

     Alabama Power

* (b) 1 - Consent of Deloitte & Touche LLP.

     Georgia Power

* (c) 1 - Consent of Deloitte & Touche LLP.

     Gulf Power

* (d) 1 - Consent of Deloitte & Touche LLP.

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       Mississippi Power

* (e) 1 - Consent of Deloitte & Touche LLP.

       Savannah Electric

* (f) 1 - Consent of Deloitte & Touche LLP.

(24) Powers of Attorney and Resolutions

       Southern Company

* (a) - Power of Attorney and resolution.

       Alabama Power

* (b) - Power of Attorney and resolution.

       Georgia Power

* (c) - Power of Attorney and resolution.

       Gulf Power

* (d) - Power of Attorney and resolution.

       Mississippi Power

* (e) - Power of Attorney and resolution.

       Savannah Electric

* (f) - Power of Attorney and resolution.

       Southern Power

* (g) - Power of Attorney and resolution.

(31) Section 302 Certifications

       Southern Company

* (a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
* (a) 2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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Alabama Power

*	(b)	1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(b)	2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Georgia Power

*	(c)	1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(c)	2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Gulf Power

*	(d)	1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(d)	2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

*	(e)	1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(e)	2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Savannah Electric

*	(f)	1	-	Certificate of Savannah Electric’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(f)	2	-	Certificate of Savannah Electric’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Southern Power

*	(g)	1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(g)	2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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(32) Section 906 Certifications

       Southern Company

* (a) - Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Alabama Power

* (b) - Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Georgia Power

* (c) - Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Gulf Power

* (d) - Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Mississippi Power

* (e) - Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Savannah Electric

* (f) - Certificate of Savannah Electric’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

       Southern Power

* (g) - Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

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