Alabama Power (ALP-PQ) 10-K 2009 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2009

OR

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

For the Transition Period from            to

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

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	5.875% Series II
5 7/8% Series GG	6.375% Series JJ
5.875% Series 2007B

Class A Preferred Stock, non-cumulative,		Georgia Power Company
Par value $25 per share
6 1/8% Series
Senior Notes
5.90% Series O	6% Series R	5.70% Series X
5.75% Series T	6% Series W	5.75% Series G2
6.375% Series 2007D	8.20% Series 2008C
Long-term debt payable to affiliated trusts, $25 liquidation amount
5 7/8% Trust Preferred Securities3

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

1	As of December 31, 2009.
2	Assumed by Georgia Power Company in connection with its merger with Savannah Electric and Power Company, effective July 1, 2006.
3	Issued by Georgia Power Capital Trust VII and guaranteed by Georgia 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

Securities registered pursuant to Section 12(g) of the Act:⁴

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

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

4 As of December 31, 2009.

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	ü
Alabama Power Company	ü
Georgia Power Company	ü
Gulf Power Company		ü
Mississippi Power Company		ü
Southern Power Company		ü

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso 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 Noo

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yesþ Noo (Response applicable only to The Southern Company at this time.)

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

	Large			Smaller
	Accelerated	Accelerated	Non-accelerated	Reporting
Registrant	Filer	Filer	Filer	Company
The Southern Company	ü
Alabama Power Company			ü
Georgia Power Company			ü
Gulf Power Company			ü
Mississippi Power Company			ü
Southern Power Company			ü

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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, 2009: $24.8 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, 2010
The Southern Company	Par Value $5 Per Share		820,372,722
Alabama Power Company	Par Value $40 Per Share		30,537,500
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,642,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

Documents incorporated by reference: specified portions of The Southern Company’s Definitive Proxy Statement on Schedule 14A relating to the 2010 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Definitive Information Statements on Schedule 14C of Alabama Power Company, Georgia Power Company, and Mississippi Power Company relating to each of their respective 2010 Annual Meetings of Shareholders are incorporated by reference into PART III.

Southern Power Company 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), (c), and (d) 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, 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 Company System	I-2
	Construction Programs	I-4
	Financing Programs	I-4
	Fuel Supply	I-4
	Territory Served by the Traditional Operating Companies and Southern Power	I-5
	Competition	I-7
	Seasonality	I-8
	Regulation	I-8
	Rate Matters	I-11
	Employee Relations	I-15
Item 1A	Risk Factors	I-16
Item 1B	Unresolved Staff Comments	I-27
Item 2	Properties	I-28
Item 3	Legal Proceedings	I-32
Item 4	Submission of Matters to a Vote of Security Holders	I-32
	Executive Officers of Southern Company	I-33
	Executive Officers of Alabama Power	I-35
	Executive Officers of Georgia Power	I-36
	Executive Officers of Mississippi Power	I-37
	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 9A(T)	Controls and Procedures	II-6
Item 9B	Other Information	II-7
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	III-1
Item 11	Executive Compensation	III-4
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	III-40
Item 13	Certain Relationships and Related Transactions, and Director Independence	III-41
Item 14	Principal Accountant Fees and Services	III-42
	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
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	Dalton Utilities
DOE	United States Department of Energy
Duke Energy	Duke Energy Corporation
Energy Act of 1992	Energy Policy Act of 1992
Energy Act of 2005	Energy Policy Act of 2005
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FMPA	Florida Municipal Power Agency
FP&L	Florida Power & Light Company
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
Hampton	City of Hampton, Georgia
IBEW	International Brotherhood of Electrical Workers
IIC	Intercompany Interchange Contract
IPP	Independent Power Producer
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
KUA	Kissimmee Utility Authority
MEAG Power	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
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PowerSouth	PowerSouth Energy Cooperative (formerly, Alabama Electric Cooperative, Inc.)
PPA	Power Purchase Agreement
Progress Energy Carolinas	Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc.
Progress Energy Florida	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, and Southern Power Company

ii 

DEFINITIONS
(continued)

Term	Meaning
RFP	Request for Proposal
RUS	Rural Utilities Service (formerly Rural Electrification Administration)
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies
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 system	Southern Company, the traditional operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless, 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 Renewable Energy	Southern Renewable Energy, Inc.
Stone & Webster	Stone & Webster, Inc.
traditional operating companies	Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company
TVA	Tennessee Valley Authority
Westinghouse	Westinghouse Electric Company LLC

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 the wholesale business, retail sales, customer growth, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, earnings, dividend payout ratios, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project, impact of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances, and also changes in 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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trusts;

• advances in technology;

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

• regulatory approvals and actions related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

• 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 of the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating public utility company. The traditional operating companies supply electric service in the states of Alabama, Georgia, Florida, and Mississippi. More particular information relating to each of the traditional 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 been in continuous existence since its incorporation in 1906.

Georgia Powerwas incorporated under the laws of the State of Georgia on June 26, 1930 and was 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.

In addition, Southern Company owns all of the common stock of Southern Power, which is also an operating public utility company. Southern Power constructs, acquires, owns, and manages 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 the States of Alabama, Florida, and Georgia on January 10, 2001, in the State of Mississippi on January 30, 2001, and in the State of North Carolina on February 19, 2007.

Southern Company also owns all of the outstanding common stock or membership interests of SouthernLINC Wireless, Southern Nuclear, SCS, Southern Holdings, Southern Renewable Energy, and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and markets these services to the public and also provides wholesale fiber optic solutions to telecommunication providers in the Southeast. Southern Nuclear operates and provides services to Alabama Power’s and Georgia Power’s nuclear plants and is currently developing new nuclear generation at Plant Vogtle. SCS is the system service company providing, at cost, specialized services to Southern Company and its subsidiary companies. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in leveraged leases. Southern Renewable Energy was formed in January 2010 to acquire, own, and construct renewable generation assets.

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 one 230,000 volt transmission line extending from Plant Gaston to the Georgia state line at which point connection is made with the Georgia Power

I-1

transmission line system.

Southern Company’s segment information is included in Note 12 to the financial statements of Southern Company in Item 8 herein.

The registrants’ Annual Reports 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 www.southerncompany.com.

The Southern Company System

Traditional Operating Companies

The traditional operating companies own generation, transmission, and distribution facilities. See PROPERTIES in Item 2 herein for additional information on the traditional operating companies’ generating facilities. Each company’s transmission facilities are connected to the respective company’s own generating plants and other sources of power (including certain generating plants owned by Southern Power) and are interconnected with the transmission facilities of the other traditional operating companies and SEGCO. For information on the State of Georgia’s integrated transmission system, see “Territory Served by the Traditional Operating Companies and Southern Power” herein.

Agreements in effect with principal neighboring utility systems provide for capacity and energy transactions that may be entered into from time to time for reasons related to reliability or economics. Additionally, the traditional 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, 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 traditional operating companies have joined with other utilities in the Southeast (including some of those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the traditional operating companies are represented on the National Electric Reliability Council.

The utility assets of the traditional operating companies and certain utility assets of Southern Power are operated as a single integrated electric system, or power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional operating companies and Southern Power. The fundamental purpose of the power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional operating company and Southern Power retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the power pool for use in serving customers of other traditional operating companies or Southern Power or for sale by the power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from power pool transactions with third parties.

Southern Company, each traditional operating company, Southern Power, Southern Nuclear, SEGCO, and other subsidiaries have contracted with SCS 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, digital wireless communications, and other services with respect to business and operations and power pool transactions. Southern Power and SouthernLINC Wireless have also secured from the traditional operating companies certain services which are furnished at cost and, in the case of Southern Power which is subject to FERC regulations, in compliance with such regulations.

Alabama Power and Georgia Power each have a contract with Southern Nuclear to operate Plant Farley and Plants

I-2

Hatch and Vogtle, respectively. In addition, Georgia Power has a contract with Southern Nuclear to develop, construct, license, and operate additional generating units at Plant Vogtle. See “Regulation – Nuclear Regulation” 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, acquires, owns, and manages generation assets and sells electricity at market-based prices in the wholesale market. Southern Power’s business activities are not subject to traditional state regulation like the traditional operating companies 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 its PPAs. However, Southern Power’s future earnings will depend on the parameters of the wholesale market, federal regulation, and the efficient operation of its wholesale generating assets. For additional information on Southern Power’s business activities, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Business Activities” of Southern Power in Item 7 herein.

In June 2008, Southern Power completed construction on Plant Franklin Unit 3 which added 659 megawatts to the Southern Company system generating capacity. In December 2008, Southern Power announced plans to construct a 720 megawatt electric generating plant in North Carolina. This new plant is expected to go into commercial operation in 2012.

On October 8, 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC from American Renewables LLC, the original developer of the project. Nacogdoches Power LLC is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 megawatts. The generating plant will be fueled from wood waste. Construction began in late 2009 and the plant is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032.

On December 17, 2009, Southern Power acquired all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC, an affiliate of LS Power. West Georgia was merged into Southern Power as of the acquisition date and Southern Power now owns a dual-fueled generating plant near Thomaston, Georgia with nameplate capacity of approximately 669 megawatts. The plant consists of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with MEAG Power and the Georgia Energy Cooperative (GEC). The MEAG Power PPA began in 2009 and expires in 2029. The GEC PPA begins in 2010 and expires in 2030.

As of December 31, 2009, Southern Power had 7,880 megawatts of nameplate capacity in commercial operation.

Other Businesses

Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in leveraged leases.

SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and markets its services to non-affiliates within the Southeast. SouthernLINC Wireless delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. SouthernLINC Wireless also provides wholesale fiber optic solutions to telecommunication providers in the Southeast under the name Southern Telecom.

On January 25, 2010, Southern Renewable Energy was formed to acquire, own, and construct renewable generation assets.

These 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 2010 through 2012, see Note 7 to the financial statements of Southern Company and each traditional operating company under “Construction Program” and Note 7 to the financial statements of Southern Power under “Expansion Program” in Item 8 herein. Estimated construction costs in 2010 are expected to be apportioned approximately as follows: (in millions)

	Southern
	Company		Alabama		Georgia		Gulf		Mississippi		Southern
	System*		Power		Power		Power		Power		Power
New generation	$	2,188	$	—	$	1,254	$	3	$	341	$	590
Environmental		545		136		259		113		11		—
Other generating facilities, including associated plant substations		528		228		154		54		39		37
New business		435		169		218		25		23		—
Transmission		461		119		265		45		32		—
Distribution		290		137		110		25		18		—
Nuclear fuel		258		111		147		—		—		—
General plant		231		85		89		6		8		—
	$	4,936	$	985	$	2,496	$	271	$	472	$	627

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

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the 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 is required to file an IRP for approval by the Georgia PSC. Through the IRP process, 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.

Financing Programs

See each of the registrant’s MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.

Fuel Supply

The traditional 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. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – “Fuel and Purchased Power Expenses” of Southern Company and each traditional operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net kilowatt-hour generated for the years 2007 through 2009.

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The traditional operating companies have agreements in place from which they expect to receive approximately 98% of their coal burn requirements in 2010. These agreements have terms ranging between one and eight years. In 2009, the weighted average sulfur content of all coal burned by the traditional operating companies was 74% sulfur. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional operating companies to remain within limits set by the Phase II acid rain requirements of the Clean Air Act. In 2009, the Southern Company system purchased approximately $18.3 million of sulfur dioxide and nitrogen oxide emissions allowances to be used in current and future periods. As additional environmental regulations are proposed that impact the utilization of coal, the traditional operating companies’ fuel mix will be monitored to ensure that the traditional operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional operating companies will continue to evaluate the need to purchase additional emissions allowances and the timing of capital expenditures for emissions control equipment. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Company and each traditional operating company in Item 7 herein for information on the Clean Air Act and global climate issues.

SCS, acting on behalf of the traditional operating companies and Southern Power, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2010, SCS has contracted for 207.5 billion cubic feet of natural gas supply under agreements with remaining terms up to 11 years. In addition to gas supply, SCS 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 traditional operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See “Rate Matters – Rate Structure and Cost Recovery Plans” herein for additional information. Southern Power’s PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.

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 of them are for 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 United States, acting through 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. See Note 3 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 Traditional Operating Companies and Southern Power

The territory in which the traditional 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 traditional operating companies. The territory has an area of approximately 120,000 square miles and an estimated population of approximately 13 million. Southern Power sells electricity at market-based prices in the wholesale market to investor-owned utilities, IPPs, municipalities, and electric cooperatives.

Alabama Power is engaged, within the State of Alabama, in the generation and purchase of electricity and the transmission, distribution, and sale of such electricity at retail in over 650 communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, 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 owns coal reserves near its Plant Gorgas 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.

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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 (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale currently to OPC, MEAG Power, Dalton, Hampton, and various electric membership corporations.

Gulf Power is engaged, within the northwestern portion of Florida, in the generation and purchase of electricity and the transmission, 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 transmission, distribution, and sale of such electricity within 23 counties in 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.

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

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 traditional operating companies provide electric service at retail or wholesale.

One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. PowerSouth 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. PowerSouth’s facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available.

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

Four electric cooperative associations, financed by the RUS, operate within Gulf Power’s service area. These cooperatives purchase their full requirements from PowerSouth 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.

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

Forty-eight municipally-owned electric distribution systems and one county-owned system receive their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power 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. MEAG Power also has a pseudo

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scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are acquired and jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. 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 Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. 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.

Southern Power has PPAs with some of the traditional operating companies and with other investor-owned utilities, IPPs, municipalities, and electric cooperatives. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 herein for additional information concerning Southern Power’s PPAs.

SCS, acting on behalf of the traditional operating companies, also has a contract with SEPA providing for the use of the traditional operating 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 Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. 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 exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice. See “Competition” herein for additional information.

Pursuant to the 1956 Utility Act, the Mississippi PSC issued “Grandfather Certificates” of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 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 which allowed IPPs to access a utility’s transmission network in order to sell electricity to other utilities.

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

Generally, the traditional operating companies have experienced, and expect to continue to experience, competition

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in their respective retail service territories in varying degrees as the result of self-generation (as described below) by customers and other factors. See also “Territory Served by the Traditional Operating Companies and Southern Power” herein for additional information concerning suppliers of electricity operating within or near the areas served at retail by the traditional operating companies.

Southern Power competes with investor owned utilities, IPPs, and others for wholesale energy sales primarily in the Southeastern United States wholesale market. The needs of this market are driven by the demands of end users in the Southeast and the generation available. Southern Power’s success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power’s plants, availability of transmission to serve the demand, price, and Southern Power’s ability to contain costs.

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 2009, Alabama Power purchased approximately 232 million kilowatt-hours from such companies at a cost of $16.5 million.

Georgia Power currently has contracts in effect with nine small power producers whereby Georgia Power purchases their excess generation. During 2009, Georgia Power purchased 14.7 million kilowatt-hours from such companies at a cost of $0.6 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2009, Georgia Power purchased 42.3 million kilowatt-hours at a cost of $19.7 million from these facilities.

Also during 2009, Georgia Power purchased energy from eight customer-owned generating facilities. Seven of the eight customers provide only energy to Georgia Power. These seven customers make no capacity commitment and are not dispatched by Georgia Power. Georgia Power does have a contract with the remaining customer for eight megawatts of dispatchable capacity and energy. During 2009, Georgia Power purchased a total of 56.3 million kilowatt-hours from the eight customers at a cost of approximately $1.9 million.

Gulf Power currently has agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases “as available” energy from customer-owned generation. During 2009, Gulf Power purchased 76 million kilowatt-hours from such companies for approximately $4.3 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 2009, Mississippi Power did not purchase any excess generation from this customer.

Seasonality

The demand for electric power generation is affected by seasonal differences in the weather. At the traditional operating companies and Southern Power, the demand for power peaks during the summer months, with market prices reflecting the demand of power and available generating resources at that time. Power demand peaks can also be recorded during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional operating companies, and Southern Power have historically sold less power when weather conditions are milder.

Regulation

State Commissions

The traditional operating companies are subject to the jurisdiction of their respective state PSCs. The PSCs 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 Traditional Operating Companies and Southern Power” and “Rate Matters” herein for additional information.

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Federal Power Act

The traditional 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 are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an “at cost standard” for services rendered by system service companies such as SCS. The FERC is also authorized to establish regional reliability organizations which are authorized to enforce reliability standards, to address impediments to the construction of transmission, and 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 generating stations having an aggregate installed capacity of 1,087,296 kilowatts.

In May 2008, the FERC issued a new 30-year license for the Morgan Falls project, located on the Chattahoochee River near Atlanta, with an effective start date of March 1, 2009. In 2007, Georgia Power began the relicensing process for Bartlett’s Ferry which is located on the Chattahoochee River near Columbus, Georgia. The current Bartlett’s Ferry license expires in 2014 and the application for a new license is expected to be submitted to the FERC in 2012. In July 2005, Alabama Power filed two applications with the FERC for new 50-year licenses for its 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 developments expired in July and August 2007. The FERC issued an annual license for the Coosa developments in August 2007 and issued an annual license for the Warrior developments in September 2007. Both of these licenses were automatically renewed in 2008 and 2009 pursuant to FERC regulations. These annual licenses provide the FERC with additional time to complete its review of the license applications. In 2006, Alabama Power initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011. In 2010, Alabama Power plans to initiate the process of developing an application to relicense the Holt hydroelectric project located on Warrior River. The current Holt license will expire in August 2015 and the application for a new license is expected to be filed prior to that time. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters” 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 2023-2034 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, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. If the FERC does not act on the new license application prior to the expiration of the existing license, the FERC is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.

Nuclear Regulation

Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978; and in accordance with the

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National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.

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 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. On June 3, 2009, the NRC approved 20-year extensions of the licenses for the operation of Plant Vogtle Units 1 and 2 to 2047 and 2049, respectively.

On August 26, 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of Georgia Power, OPC, MEAG Power, and Dalton (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license for Plant Vogtle Units 3 and 4, which, if licensed by the NRC, are scheduled to be placed in service in 2016 and 2017, respectively. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Construction — Nuclear” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Georgia Power under “Construction — Nuclear” in Item 8 herein for additional information.

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.

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 existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or market-based rates for Southern Power. There is no assurance, however, that all such costs will be recovered.

Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional operating company, Southern Power, and SEGCO. In addition, existing environmental laws and regulations may be changed or new laws and regulations may be adopted or otherwise become applicable to Southern Company, the traditional operating companies, Southern Power, or SEGCO, including laws and regulations designed to address global climate change, air quality, water quality, management of waste materials and coal combustion byproducts, including coal ash, or other environmental, public health, and welfare concerns. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company and each of the traditional operating companies in Item 7 herein for additional information about the Clean Air Act and other environmental issues, including, but not limited to, the litigation brought by the EPA under the New Source Review provisions of the Clean Air Act, possible additional and/or revised regulations related to air and water quality, possible climate change legislation and regulation, and possible regulation of coal combustion byproducts. Also see MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Power in Item 7 herein for information about the environmental issues and possible climate change legislation and regulation.

Southern Company, the traditional 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 requirements pertaining to climate change, air quality, water quality, and management of waste materials and coal combustion byproducts, including coal ash, 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 affect unit retirement and replacement decisions and 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.

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Rate Matters

Rate Structure and Cost Recovery Plans

The rates and service regulations of the traditional 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, Alabama Power, Gulf Power, and Mississippi Power are generally 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.

Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions at the traditional operating companies. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed. Gulf Power’s and Mississippi Power’s fuel cost recovery provisions are adjusted annually to reflect increases or decreases in such costs. Georgia Power filed for an adjustment to its fuel cost recovery rate on December 15, 2009. If approved by the Georgia PSC, the adjustment would be effective on April 1, 2010. Alabama Power’s fuel clause is adjusted as required. Revenues are adjusted for differences between recoverable costs and amounts actually recovered in current rates.

Approved environmental compliance and storm damage costs are recovered at Alabama Power and Mississippi Power through cost recovery provisions approved by their respective state PSCs. Within limits approved by their respective PSCs, these rates are adjusted to reflect increases or decreases in such costs as required.

Georgia Power’s environmental compliance costs are recovered in base rates. Under the 2007 retail rate plan, an environmental compliance cost recovery tariff was implemented effective January 1, 2008 to allow recovery of environmental costs mandated by state and federal regulation. See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and Georgia Power under “Retail Regulatory Matters — Rate Plans” in Item 8 herein for additional information.

See “Integrated Resource Planning” herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Construction — Nuclear” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Georgia Power under “Construction — Nuclear” in Item 8 herein for a discussion of the Georgia Nuclear Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which allow Georgia Power to recover financing costs for construction of the new nuclear units during the construction period beginning in 2011.

Alabama Power recovers the cost of certificated new plant and purchased power capacity through cost recovery provisions which are approved annually. Gulf Power files a rate clause request annually with the Florida PSC to recover costs associated with purchased power capacity, energy conservation, and environmental compliance. 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 traditional operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters” and Note 3 to the financial statements of each of the traditional 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 traditional operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and environmental compliance costs through rates.

The traditional operating companies and Southern Power are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

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Integrated Resource Planning

Georgia Power

Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electrical needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to get cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs will be recoverable through rates.

On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009, which did not include any proposed change to the estimated construction cost as certified by the Georgia PSC in March 2009. On February 25, 2010, the Georgia PSC approved the expenditures made by Georgia Power pursuant to the certification through June 30, 2009. The Georgia PSC also ordered that in its future semi-annual construction monitoring reports, Georgia Power will report against a total certified cost of approximately $6.1 billion, which is the effective certified amount after giving effect to the Georgia Nuclear Energy Financing Act. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

In connection with its approval of the updated IRP on March 17, 2009, the Georgia PSC also approved Georgia Power’s plan for the installation of emissions controls at its Plant Branch Units 1 — 4 and Plant Yates Units 6 and 7. However, Georgia Power has suspended further engineering and construction activity on the emissions control projects at Plant Branch Units 1 and 2 and Plant Yates Units 6 and 7 until more information is available from the rulemaking and legislative process, thereby mitigating the risk related to significant capital expenditures associated with those projects. Georgia Power continues to review the economic feasibility of installing controls at Plant Branch Units 3 and 4. Georgia Power intends to continue to operate these units in the near term and reevaluate the economics of installing emissions controls on these units as more information becomes available.

Georgia Power plans to convert the 155-megawatt coal-fired Plant Mitchell Unit 3 to a renewable biomass facility fueled primarily with wood chips. Georgia Power filed a request for approval of the certification of the Plant Mitchell biomass conversion with the Georgia PSC in August 2008. On March 17, 2009, the Georgia PSC approved Georgia Power’s request for certification of the Plant Mitchell biomass conversion. Georgia Power filed an air permit application for the conversion with the Georgia Environmental Protection Division in December 2008. Georgia Power expects to be granted an air permit in 15 to 18 months from the filing date. With the uncertainty of how future EPA regulations might affect allowable industrial boiler emissions, Georgia Power has decided to delay the conversion of Plant Mitchell Unit 3 to biomass until the EPA rules are better defined, which is expected in April 2010. Georgia Power had originally planned to begin retrofit construction at Plant Mitchell in April 2011 with the unit becoming operational in June 2012. A new project schedule has yet to be determined.

On January 29, 2010, Georgia Power filed its 2010 IRP for approval by the Georgia PSC. The 2010 IRP projected that Georgia Power’s current supply-side and demand-side resources are sufficient to provide a cost effective and reliable source of capacity and energy at least through 2014. The 2010 IRP identifies potential regulations relating to coal combustion byproducts and maximum achievable control technology for hazardous air pollutants, as well as potential legislation or regulations that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts,” and “Environmental Matters — Global Climate Issues” of Georgia Power in Item 7 herein. While neither proposed nor final EPA regulations have been released at this time with respect to hazardous air pollutants or coal combustion byproducts, Georgia Power currently estimates that compliance would be required by about January 2015. The 2010 IRP includes preliminary retirement studies under a variety of potential scenarios for units at seven of Georgia Power’s coal-fired generating plants. These studies indicated that, depending on the final requirements in both of these anticipated EPA regulations and any legislation or regulation relating to greenhouse gas emissions, as well as estimates of long-term fuel prices, Georgia Power may conclude that it is more economical to retire certain coal-fired generating units than to install the required controls and/or that Georgia Power may not be able to complete installation of required controls on all such units by 2015 where such installation is determined to be more economical. Given the uncertainty and the amount of capacity at

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risk of retirement, Georgia Power has restarted its 2015 RFP for 1,000 megawatts of capacity and energy. However, Georgia Power’s capacity needs could change significantly depending on the final requirements resulting from these environmental regulations.

The Georgia PSC certified the construction of Plant McDonough Units 4, 5, and 6 (natural gas-fired units) and the retirement of Plant McDonough Units 1 and 2 (coal-fired units) in 2007. On August 10, 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. On September 30, 2009, Georgia Power amended the report. As amended, the report includes a request for an increase in the certified costs to construct Plant McDonough. The Georgia PSC held a hearing in December 2009 and is scheduled to render its decision on March 16, 2010.

The ultimate outcome of these matters cannot be determined at this time.

See Note 3 to the financial statements of Southern Company and Georgia Power in Item 8 herein for additional information regarding the proposed Plant Vogtle Units 3 and 4.

Gulf Power

Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power’s estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state’s electric utilities are reviewed by the Florida PSC and subsequently classified as either “suitable” or “unsuitable.” The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical power plant site certification proceedings. Under Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC. At least every five years, the Florida PSC must conduct proceedings to establish numerical goals for all investor-owned electric utilities and certain municipal or cooperative electric utilities in the state to reduce the growth rates of weather-sensitive peak demand, to reduce and control the growth rates of electric consumption, and to increase the conservation of expensive resources, such as petroleum fuels. Overall residential kilowatts and kilowatt hours goals and overall commercial/industrial kilowatt and kilowatt hours goals for each utility are set by the Florida PSC for each year over a 10-year period. The goals are to be based on an estimate of the total cost effective kilowatts and kilowatt hours savings reasonably achievable through demand-side management in each utility’s service area over a 10-year period. Once goals have been set, each affected utility must develop and submit plans and programs to meet the overall goals within its service area to the Florida PSC for review and approval. Once approved, the utilities are required to submit periodic reports which the Florida PSC then uses to prepare its annual report to the Governor and Legislature of the goals that have been established and the progress towards meeting those goals.

Gulf Power’s most recent 10-year site plan was classified by the Florida PSC as “suitable” in December 2009. Gulf Power’s most recent 10-year site plan and environmental compliance plan identify potential environmental regulations relating to maximum achievable control technology for hazardous air pollutants and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts,” and “Environmental Matters — Global Climate Issues” of Gulf Power in Item 7 herein. The site plan and environmental compliance plan include preliminary retirement studies under a variety of potential scenarios for units at each of Gulf Power’s coal-fired generating plants. These studies indicate that, depending on the final requirements in these anticipated EPA regulations and any legislation or regulations relating to greenhouse gas emissions, as well as estimates of long-term fuel prices, Gulf Power may conclude that it is more economical to retire certain of its coal-fired generating units prior to 2020 and to replace such units with new or purchased capacity.

Also in December 2009, the Florida PSC adopted new numerical conservation goals for Gulf Power along with other electric utilities in the state. The Florida PSC adopted more aggressive goals due in part to the consideration of possible greenhouse gas emissions costs incurred in connection with possible climate change legislation and a change in the manner in which the Florida PSC considers the effect of so-called “free-riders” on the level of

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conservation reasonably achievable through utility programs. Gulf Power’s plans and programs to meet the new goals are scheduled to be submitted to the Florida PSC for review by the end of the first quarter 2010. The costs of implementing Gulf Power’s conservation plans and programs are recovered through specific conservation recovery rates set annually by the Florida PSC.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

On December 7, 2009, Mississippi Power filed its 2010 IRP with the Mississippi PSC. The filing was made in connection with the Mississippi PSC certification proceedings relating to the proposed Kemper County IGCC project. In the 2010 IRP, Mississippi Power projected that it will have a need for new capacity in the 2013 to 2015 timeframe. The 2010 IRP indicated a need range of approximately 200 megawatts to 300 megawatts in 2014, which reflects growth in load and the anticipated retirement of older gas steam units Plant Eaton Units 1 through 3 and Plant Watson Units 1 through 3 in 2012 and 2013, respectively. In addition, due to potential retirements of existing coal units, the Mississippi PSC found a need in 2015 that ranges from 304 megawatts to 1,276 megawatts.

The range of needs for 2015 is based on potential environmental regulations relating to maximum achievable control technology for hazardous air pollutants, as well as potential legislation or regulations that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” and “Environmental Matters — Global Climate Issues” of Mississippi Power in Item 7 herein. Depending on the final requirements in the anticipated EPA regulations and any legislation or regulation relating to greenhouse gas emissions, as well as estimates of long-term fuel prices, Mississippi Power may conclude that it is more economical to discontinue burning coal at certain coal-fired generating units than to install the required controls.

Mississippi Power’s 2010 IRP indicated that Mississippi Power plans to construct the Kemper County IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Base Load Construction Legislation

In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the Governor in May 2008 to enhance the Mississippi PSC’s authority to facilitate development and construction of base load generation in the State of Mississippi (Baseload Act). The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. The effect of this legislation on Southern Company and Mississippi Power cannot now be determined.

On January 16, 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct, and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 herein for additional information.

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Employee Relations

The Southern Company system had a total of 26,112 employees on its payroll at December 31, 2009.

	Employees at December 31, 2009
Alabama Power		6,842
Georgia Power		8,599
Gulf Power		1,365
Mississippi Power		1,285
SCS		4,184
Southern Holdings*		—
Southern Nuclear		3,485
Southern Power**		—
Other		352
Total		26,112

*	Southern Holdings has agreements with SCS whereby all employee services are rendered at cost.
**	Southern Power has no employees. Southern Power has agreements with SCS and the traditional operating companies whereby employee services are rendered at amounts in compliance with FERC regulations.

The traditional 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.

On August 15, 2009, a five-year labor agreement between Alabama Power and nine local unions with the IBEW expired. Prior to the expiration of this agreement, Alabama Power and the IBEW entered into a new five-year labor agreement with a ratification date of May 29, 2009. Parts of this new agreement took effect on August 15, 2009, when the original agreement expired, and the remainder took effect on January 1, 2010. The new agreement expires on August 15, 2014.

Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2011. 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.

The agreement between Gulf Power and the IBEW covering wages and working conditions was scheduled to expire on October 15, 2009. The agreement has not been terminated by either party and remains in effect through October 14, 2010. Negotiations for a new agreement began in September 2009 and are on-going.

Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect until August 16, 2010. 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.

Southern Nuclear and the IBEW ratified a labor agreement for certain employees at Plants Hatch and Vogtle on May 21, 2009. The agreement is effective through June 30, 2011. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley was ratified on July 8, 2009. The agreement became effective on August 15, 2009 and will remain in effect through August 15, 2014.

The agreements also make the terms of the pension plans for the companies discussed above subject 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 traditional 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 rates and charges, 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 traditional operating companies and by Southern Power must be approved by the FERC. These wholesale rates could be affected absent the ability to conduct business pursuant to FERC market-based rate authority. Additionally, the respective state PSCs must approve the traditional operating companies’ requested rates for retail customers. While the retail rates of the traditional operating companies are designed to provide for the full recovery of costs (including a reasonable return on invested capital), there can be no assurance that a state PSC, in a future rate proceeding, will not attempt to alter the timing or amount of certain costs for which recovery is sought or to modify the current authorized rate of return.

Southern Company and its subsidiaries believe the necessary permits, approvals, and certificates have been obtained for their respective 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.

Risks Related to Environmental and Climate Change Legislation and Regulation

Southern Company’s, the traditional operating companies’, and Southern Power’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, renewable energy standards, air quality, coal combustion byproducts, and other matters and the incurrence of environmental liabilities could affect unit retirement decisions and negatively impact the net income, cash flows, and financial condition of Southern Company, the traditional operating companies, or Southern Power.

Southern Company, the traditional operating companies, and Southern Power are subject to extensive federal, state, and local environmental requirements which, among other things, regulate air emissions, water usage and discharges, and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires Southern Company, the traditional operating companies, and Southern Power 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, the traditional operating companies, and Southern Power expect that they will increase in the future. Through 2009, Southern Company had invested approximately $7.5 billion in capital projects to comply with these requirements, with annual totals of $1.3 billion, $1.6 billion, and $1.5 billion for 2009, 2008, and 2007, respectively. Southern Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $545 million, $721 million, and $1.2 billion for 2010, 2011, and 2012,

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respectively. Because the compliance strategy is impacted by changes to existing environmental laws, statutes, and regulations, the cost, availability, and existing inventory of emissions allowances, and the fuel mix, the ultimate outcome cannot be determined at this time.

If Southern Company, any traditional operating company, or Southern Power fails to comply with environmental laws and regulations, even if caused by factors beyond its control, that failure may result in the assessment of civil or criminal penalties and fines. The EPA has filed civil actions against Alabama Power and Georgia Power and issued notices of violation to Gulf Power and Mississippi Power alleging violations of the new source review provisions of the Clean Air Act. Southern Company is a party to suits alleging emissions of carbon dioxide, a greenhouse gas, contribute to global warming. An adverse outcome in any of these matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect unit retirement and replacement decisions, and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or market-based rates for Southern Power.

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

Existing environmental laws and regulations may be revised or new laws and regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns may be adopted or become applicable to Southern Company, the traditional operating companies, and Southern Power. For example, federal legislative proposals that would impose mandatory requirements on greenhouse gas emissions and renewable energy standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. In 2007, the U. S. Supreme Court ruled that the EPA has authority to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under certain provisions of the Clean Air Act applicable to stationary sources, including power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to such sources. The EPA has stated that it expects to finalize these proposed rules in March 2010.

In addition, the EPA is expected to issue additional regulations and designations with respect to air quality under the Clean Air Act, including eight-hour ozone standards, sulfur dioxide standards, a replacement Clean Air Interstate Rule relating to nitrogen oxide and sulfur dioxide emissions, and a Maximum Achievable Control Technology rule for coal and oil-fired electric generating units, which will likely address numerous hazardous air pollutants, including mercury.

In addition, the EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions.

The cost impact of such legislation, regulation, new interpretations, or international negotiations would depend upon the specific requirements enacted and cannot be determined at this time. For example, the impact of currently proposed legislation relating to greenhouse gas emissions would depend on a variety of factors, including the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these

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limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates or market-based rates for Southern Power.

Although the outcome cannot be determined at this time, legislation or regulation related to greenhouse gas emissions, renewable energy standards, air quality, coal combustion byproducts and other matters, individually or together, are likely to result in significant and additional compliance costs, including significant capital expenditures, and could result in additional operating restrictions. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units of the traditional operating companies. Additional compliance costs and costs related to potential unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered from customers. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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 traditional 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. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection. The financial condition, net income, and cash flows of Southern Company and its utility subsidiaries could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

The net income of Southern Company, the traditional operating companies, and Southern Power could be negatively impacted by competitive activity in the wholesale electricity markets.

Competition at the wholesale level continues to expand and evolve in the electricity markets. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity markets has increased due to greater participation by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers, and brokers. FERC rules related to transmission are designed to facilitate competition in the wholesale market on a nationwide basis by providing greater flexibility and more choices to wholesale power customers, including initiatives designed to promote and encourage the integration of renewable sources of supply. Moreover, along with transactions contemplating physical delivery of energy, futures contracts and derivatives are traded on various commodities exchanges. Southern Company, the traditional operating companies, and Southern Power cannot predict the impact of these and other such developments, nor can they predict the effect of changes in levels of wholesale supply and demand, which are typically driven by factors beyond their control.

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. Substantially all of Southern Company’s consolidated assets are held by subsidiaries. Southern Company’s ability to meet its financial obligations and to pay dividends on its common stock 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 regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred and preference stock dividends. Southern Company’s subsidiaries are separate legal entities and have no obligation to provide Southern Company with funds for its payment obligations.

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The financial performance of Southern Company and its subsidiaries may be adversely affected if they are unable to successfully operate their facilities or perform certain corporate functions.

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

• operator error 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;

• compliance with mandatory reliability standards, including mandatory cyber security standards;

• information technology system failure;

• cyber intrusion; and

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

A severe drought could reduce the availability of water and restrict or prevent the operation of certain generating facilities. A decrease or elimination of revenues from the electric generation, transmission, or distribution 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 traditional operating company or Southern Power and of Southern Company.

The traditional operating companies could be subject to higher costs and penalties as a result of mandatory reliability standards.

As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission systems, including the traditional operating companies, are subject to mandatory reliability standards enacted by the North American Reliability Corporation and enforced by the FERC. Compliance with the mandatory reliability standards may subject the traditional operating companies and Southern Company to higher operating costs and may result in increased capital expenditures. If any traditional operating company is found to be in noncompliance with the mandatory reliability standards, the traditional operating company could be subject to sanctions, including substantial monetary penalties.

The revenues of Southern Company, the traditional 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 traditional operating company or Southern Power and of Southern Company.

Most of Southern Power’s generating capacity has been sold to purchasers under PPAs. In addition, the traditional 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 traditional operating companies have a rigorous credit evaluation process, 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 traditional 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

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credit evaluation predicts. Additionally, neither Southern Power nor any traditional operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. If a PPA is not renewed, a replacement PPA cannot be assured.

Southern Company, the traditional operating companies, and Southern Power may incur additional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. The facilities of the traditional operating companies and Southern Power require ongoing capital expenditures.

The businesses of the registrants require substantial capital expenditures for investments in new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards. Certain of the traditional operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company intends to continue its strategy of developing and constructing other new facilities, including new nuclear generating units, combined cycle units, including the proposed integrated coal gasification combined cycle facility, and the proposed biomass generating units, expanding existing facilities, and adding environmental control equipment. These types of projects are long-term in nature and may involve facility designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:

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

• work stoppages;

• contractor or supplier non-performance under construction or other agreements;

• delays in or failure to receive necessary permits, approvals, and other regulatory authorizations;

• impacts of new and existing laws and regulations, including environmental laws and regulations;

• continued public and policymaker support for such projects;

• adverse weather conditions;

• unforeseen engineering problems;

• changes in project design or scope;

• environmental and geological conditions;

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

• unanticipated cost increases, including materials and labor; and

• attention to other projects.

In addition, with respect to the construction of new nuclear units, a major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units. If a traditional 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 and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and there is no assurance that the traditional operating company will be able to recover such expenditures through regulated rates. 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 traditional operating company or Southern Power and of Southern Company.

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Furthermore, if construction projects are not completed according to specification, a traditional 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 traditional 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 traditional operating companies and Southern Power less competitive.

A key element of the business model of Southern Company, the traditional operating companies, and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, 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 station power electric production. If this were to happen and if these technologies achieved economies of scale, the market share of Southern Company, the traditional operating companies, and Southern Power could be eroded, and the value of their respective electric generating facilities could be reduced. It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by Southern Company, the traditional operating companies, and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional 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, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units and the construction of Plant Vogtle Units 3 and 4. The six existing units are operated by Southern Nuclear and represent approximately 3,680 megawatts, or 8.6%, of Southern Company’s generation capacity as of December 31, 2009. 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 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 any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations 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 their 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 operations and energy marketing operations of Southern Company, the traditional operating companies, and Southern Power are subject to risks, many of which are beyond their control, including

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changes in power prices and fuel costs, that may reduce Southern Company’s, the traditional operating companies’, and Southern Power’s revenues and increase costs.

The generation operations and energy marketing operations of Southern Company, the traditional 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 traditional operating companies, and Southern Power receive from the sale of power. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Southern Company, the traditional operating companies, and Southern Power attempt to mitigate risks associated with fluctuating fuel costs by passing these costs on to customers through the traditional operating companies’ 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, uranium, fuel oil, and other fuels used in the generation facilities of the traditional operating companies and Southern Power 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 the Southern Company system, its competitors, or third party providers;

• the financial condition of market participants;

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

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

Historically, the traditional operating companies from time to time have experienced underrecovered fuel cost balances and deficits in their storm cost recovery reserve balances and may experience such balances in the future. While the traditional operating companies are generally authorized to recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs through special rate provisions administered by the respective PSCs, 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 traditional operating company and Southern Company.

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A downgrade in the credit ratings of Southern Company, the traditional operating companies, or Southern Power could negatively affect their ability to access capital at reasonable costs and/or could require Southern Company, the traditional operating companies, or Southern Power to post collateral or replace certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for Southern Company, the traditional operating companies, and Southern Power, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. Southern Company, the traditional operating companies, and Southern Power could experience a downgrade in their ratings if any of the rating agencies conclude that the level of business or financial risk of the industry or Southern Company, the traditional operating companies, or Southern Power has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade Southern Company, the traditional operating companies, or Southern Power, borrowing costs would increase, its pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, collateral requirements may be triggered in a number of contracts.

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 traditional operating companies and Southern Power, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures 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. These risks are managed through risk management policies, limits, and procedures. These risk management policies, limits, and procedures might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered for hedging purposes might not off-set the underlying exposure being hedged as expected resulting in financial losses. 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. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. 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 traditional operating companies and Southern Power may not be able to obtain adequate fuel supplies, which could limit their ability to operate their facilities.

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

The traditional operating companies are dependent on coal for much of their electric generating capacity. Each traditional 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 traditional operating companies. The suppliers under these agreements may experience financial or technical problems which inhibit their ability to fulfill their obligations to the traditional operating companies. In addition, the suppliers under these agreements may not be required to supply coal to the traditional operating companies under certain circumstances, such as in the event of a natural disaster. If the traditional operating companies are unable to obtain their coal requirements under these contracts, the traditional 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 traditional 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

I-23

the event production or distribution is curtailed, such as in the event of a hurricane.

In addition, world market conditions for fuels can impact the availability of natural gas, coal, and uranium.

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 traditional 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 traditional operating companies or Southern Power purchase capacity on the open market or build additional generation capabilities. Because regulators may not permit the traditional operating companies to pass all of these purchase or construction costs on to their customers, the traditional 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 traditional operating companies’ recovery in customers’ rates. Under Southern Power’s long-term fixed price PPAs, Southern Power would not have the ability to recover any of these costs. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and Southern Company.

Demand for power could decrease or fail to grow at expected rates, resulting in stagnant or reduced revenues, limited growth opportunities, and potentially stranded generation assets.

Southern Company, the traditional operating companies, and Southern Power each engage in a long-term planning process to determine the optimal mix and timing of new generation assets required to serve future load obligations. This planning process must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including regional economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional operating companies to adjust rates to recover the costs of new generation assets while such assets are being constructed, the traditional operating companies may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of additional capacity and the traditional operating companies’ recovery in customers’ rates. Under Southern Power’s model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power may not be able to extend its existing PPAs or to find new buyers for existing generation assets as existing PPAs expire, or it may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and Southern Company.

The operating results of Southern Company, the traditional operating companies, and Southern Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis. In addition, significant weather events, such as hurricanes, tornadoes, floods, and droughts, or a terrorist attack could result in substantial damage to or limit the operation of the properties of the traditional operating companies and Southern Power and could negatively impact results of operation, financial condition, and liquidity.

Electric power supply is generally a seasonal business. In many parts of the country, demand for power peaks during the 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 traditional operating companies, and Southern Power in the future may fluctuate substantially on a seasonal basis. In addition, the traditional operating companies and Southern Power have historically sold less power 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 traditional operating companies, and Southern Power.

In addition, volatile or significant weather events or a terrorist attack could result in substantial damage to the transmission and distribution lines of the traditional operating companies and the generating facilities of the

I-24

traditional operating companies and Southern Power. The traditional operating companies and Southern Power have significant investments in the Atlantic and Gulf Coast regions which could be subject to major storm activity. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.

Each traditional operating company maintains a reserve for property damage to cover the cost of damages from weather events to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. In the event a traditional operating company experiences any of these weather events or any natural disaster, or other catastrophic event, such as a terrorist attack, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC. While the traditional operating companies generally are entitled to recover prudently incurred costs incurred in connection with such an event, any denial by the applicable state PSC or delay in recovery of any portion of such costs could have a material negative impact on a traditional operating company’s and Southern Company’s results of operations, financial condition, and liquidity.

In addition, damages resulting from significant weather events within the service territory of any traditional operating company or affecting Southern Power’s customers may result in the loss of customers and reduced demand for electricity. For example, Hurricane Katrina hit the Gulf Coast of Mississippi in August 2005 and caused substantial damage within Mississippi Power’s service territory. As of December 31, 2009, Mississippi Power had approximately 4.6% fewer retail customers as compared to pre-storm levels. Any significant loss of customers or reduction in demand for electricity could have a material negative impact on a traditional operating company’s, Southern Power’s, and Southern Company’s results of operations, financial condition, and liquidity.

Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company’s and its subsidiaries’ results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skillset to future needs, or unavailability of contract resources may lead to operating challenges or increased costs. Such operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development, especially with the workforce needs associated with new nuclear construction. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries’ ability to manage and operate their businesses. If Southern Company and its subsidiaries, including the traditional operating companies, are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

Risks Related to Market and Economic Volatility

The business of Southern Company, the traditional operating companies, and Southern Power is dependent on their ability to successfully access funds through capital markets and financial institutions. The inability of Southern Company, any traditional operating company, or Southern Power to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on to achieve future earnings and cash flows.

Southern Company, the traditional 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 traditional operating company, or Southern Power is not able to access capital at competitive rates, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operating companies, or Southern Power may otherwise rely on to achieve future earnings and cash flows. In addition, Southern Company, the traditional operating companies, and Southern Power rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of Southern Company, the traditional operating companies, and Southern Power believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions may increase its cost of borrowing or adversely affect its ability to raise capital through the issuance of securities or other borrowing arrangements or its ability to secure committed bank lending agreements used as back-up sources of

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capital. Such disruptions could include:

• an economic downturn or uncertainty;

• the bankruptcy of an unrelated energy company or financial institution;

• capital markets volatility and interruption;

• financial institution distress;

• market prices for electricity and gas;

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

• war or threat of war; or

• the overall health of the utility and financial institution industries.

Market performance and other changes may decrease the value of benefit plans and decommissioning trust assets or may increase medical costs, which then could require significant additional funding.

The performance of the capital markets affects the values of the assets held in trust under Southern Company’s pension and postretirement benefit plans and the assets held in trust to satisfy obligations to decommission Alabama Power’s and Georgia Power’s nuclear plants. Southern Company, Alabama Power, and Georgia Power have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below projected return rates. A decline in the market value of these assets, as has been experienced in prior periods, may increase the funding requirements relating to Southern Company’s benefit plan liabilities and Alabama Power’s and Georgia Power’s decommissioning obligations. Additionally, changes in interest rates affect the liabilities under Southern Company’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. Southern Company and its subsidiaries are also facing rising medical benefit costs, including the current costs for active and retired employees. It is possible that these costs may increase at a rate that is significantly higher than anticipated. If Southern Company is unable to successfully manage benefit plan assets and medical benefit costs and Alabama Power and Georgia Power are unable to successfully manage the decommissioning trust funds, results of operations and financial position could be negatively affected. Additionally, Southern Company and its subsidiaries may also be affected by the potential passage of healthcare legislation.

Southern Company, the traditional operating companies, and Southern Power are subject to risks associated with a changing economic environment, which could impact their ability to obtain adequate insurance and the financial stability of the customers of the traditional operating companies and Southern Power.

The financial condition of some insurance companies, the threat of terrorism, and the hurricanes that affected the Gulf Coast, among other things, have had disruptive effects on the insurance industry. The availability of insurance covering risks that Southern Company, the traditional operating companies, Southern Power, and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the traditional operating companies, and Southern Power are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms.

Additionally, Southern Company, the traditional operating companies, and Southern Power are exposed to risks related to general economic conditions in their applicable service territory and are thus impacted by the economic cycles of the customers each serves. Any economic downturn or disruption of financial markets could negatively affect the financial stability of the customers and counterparties of the traditional operating companies and Southern

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Power. As territories served by the traditional operating companies and Southern Power experience economic downturns, energy consumption patterns may change and revenues may be negatively impacted. Additionally, customers could voluntarily reduce their consumption of electricity in response to decreases in their disposable income or individual conservation efforts. If commercial and industrial customers experience economic downturns, their consumption of electricity may decline. As a result, revenues may be negatively impacted.

Further, the results of operations of the traditional operating companies and Southern Power are affected by customer growth in their applicable service territory. Customer growth and customer usage can be affected by economic factors in the service territory of the traditional operating companies and Southern Power and elsewhere, including, for example, job and income growth, housing starts, and new home prices. A population decline and/or business closings in the territory served by the traditional operating companies or Southern Power or slower than anticipated customer growth as a result of the current recession or otherwise could also have a negative impact on revenues and could result in greater expense for uncollectible customer balances.

As with other parts of the country, the territories served by the traditional operating companies and Southern Power have been impacted by the current economic recession. The traditional operating companies have experienced some decline in the rate of residential and commercial sales growth, and also have experienced declining sales to commercial and industrial customers due to the economic recession. Southern Power is expected to experience reduced future revenues for its requirements customers due to the economic recession. The timing and extent of the recovery cannot be predicted.

These and the other factors discussed above could adversely affect Southern Company’s, the traditional operating companies’, and Southern Power’s level of future net income.

Energy conservation and energy price increases could negatively impact financial results.

A number of regulatory and legislative bodies have proposed or introduced requirements and/or incentives to reduce energy consumption by certain dates. Conservation programs could impact the financial results of Southern Company, the traditional operating companies, and Southern Power in different ways. To the extent conservation results in reduced energy demand or significantly slows the growth in demand, the value of wholesale generation assets of the traditional operating companies and Southern Power and other unregulated business activities could be adversely impacted. In addition, conservation could negatively impact the traditional operating companies depending on the regulatory treatment of the associated impacts. If any traditional operating company is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional operating company and Southern Company. Southern Company, the traditional operating companies, and Southern Power could also be impacted if any future energy price increases result in a decrease in customer usage. Southern Company, the traditional operating companies, and Southern Power are unable to determine what impact, if any, conservation and increases in energy prices will have on financial condition or results of operations.

Item 1B. UNRESOLVED STAFF COMMENTS.

None.

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Item 2. PROPERTIES

Electric Properties – The Electric Utilities

The traditional operating companies, Southern Power, and SEGCO, at December 31, 2009, owned and/or operated 34 hydroelectric generating stations, 34 fossil fuel generating stations, three nuclear generating stations, and 12 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
Kraft	Port Wentworth, GA		281,136
McDonough (4)	Atlanta, GA		490,000
McIntosh	Effingham County, GA		163,117
McManus	Brunswick, GA		115,000
Mitchell	Albany, GA		125,000
Scherer	Macon, GA		750,924	(5)
Wansley	Carrollton, GA		925,550	(6)
Yates	Newnan, GA		1,250,000
Georgia Power Total			9,600,427
Crist	Pensacola, FL		970,000
Daniel	Pascagoula, MS		500,000	(7)
Lansing Smith	Panama City, FL		305,000
Scholz	Chattahoochee, FL		80,000
Scherer Unit 3	Macon, GA		204,500	(5)
Gulf Power Total			2,059,500
Daniel	Pascagoula, MS		500,000	(7)
Eaton	Hattiesburg, MS		67,500
Greene County	Demopolis, AL		200,000	(2)
Sweatt	Meridian, MS		80,000
Watson	Gulfport, MS		1,012,000
Mississippi Power Total			1,859,500
Gaston Units 1-4	Wilsonville, AL
SEGCO Total			1,000,000	(8)
Total Fossil Steam			21,097,965
NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total			1,720,000
Hatch	Baxley, GA		899,612	(9)
Vogtle	Augusta, GA		1,060,240	(10)
Georgia Power Total			1,959,852
Total Nuclear Steam			3,679,852
COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total			720,000
Boulevard	Savannah, GA		59,100
Bowen	Cartersville, GA		39,400
Intercession City	Intercession City, FL		47,667	(11)
Kraft	Port Wentworth, GA		22,000
McDonough	Atlanta, GA		78,800
McIntosh Units 1 through 8	Effingham County, GA		640,000
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			2,025,689
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	(12)
Sweatt	Meridian, MS		39,400

I-28

		Nameplate
Generating Station	Location	Capacity (1)
		(Kilowatts)
Watson	Gulfport, MS		39,360
Mississippi Power Total			226,052
Dahlberg	Jackson County, GA		756,000
Oleander	Cocoa, FL		791,301
Rowan	Salisbury, NC		455,250
West Georgia	Thomaston, GA		668,800
Southern Power Total			2,671,351
Gaston(SEGCO)	Wilsonville, AL		19,680	(8)
Total Combustion Turbines			5,717,172
COGENERATION
Washington County	Washington County, AL		123,428
GE Plastics Project	Burkeville, AL		104,800
Theodore	Theodore, AL		236,418
Total Cogeneration			464,646
COMBINED CYCLE
Barry	Mobile, AL
Alabama Power Total			1,070,424
McIntosh Units 10&11	Effingham County, GA
Georgia Power Total			1,318,920
Smith	Lynn Haven, FL
Gulf Power Total			545,500
Daniel (Leased)	Pascagoula, MS
Mississippi Power Total			1,070,424
Franklin	Smiths, AL		1,857,820
Harris	Autaugaville, AL		1,318,920
Rowan	Salisbury, NC		530,550
Stanton Unit A	Orlando, FL		428,649	(13)
Wansley	Carrollton, GA		1,073,000
Southern Power Total			5,208,939
Total Combined Cycle			9,214,207
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		46,944
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			1,668,079
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	(14)
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			2,758,415
Total Generating Capacity			42,932,257

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)	McDonough Units 1 and 2 are scheduled to be retired in October 2011 and October 2010, respectively.
(5)	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.

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(6)	Capacity shown is Georgia Power’s portion (53.5%) of total plant capacity.
(7)	Represents 50% of the plant which is owned as tenants in common by Gulf Power and Mississippi Power.
(8)	SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information.
(9)	Capacity shown is Georgia Power’s portion (50.1%) of total plant capacity.
(10)	Capacity shown is Georgia Power’s portion (45.7%) of total plant capacity.
(11)	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 Florida operates the unit.
(12)	Generation is dedicated to a single industrial customer.
(13)	Capacity shown is Southern Power’s portion (65%) of total plant capacity.
(14)	Capacity shown is Georgia Power’s portion (25.4%) of total plant capacity. OPC operates the plant.

Except as discussed below under “Titles to Property,” the principal plants and other important units of the traditional 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, 2009, the unamortized portion of this cost was approximately $21 million.

In 2009, the maximum demand on the traditional operating companies, Southern Power, and SEGCO was 34,471,000 kilowatts and occurred on June 22, 2009. The all-time maximum demand of 38,777,000 kilowatts on the traditional operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional operating companies, Southern Power, and SEGCO in 2009 was 26.4%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands.

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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
																					Progress
	Total		Alabama			Power			Georgia						MEAG						Energy			Southern
	Capacity		Power			South			Power			OPC			Power			Dalton			Florida			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 Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power’s bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit’s variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC’s disallowances of Plant Vogtle Units 1 and 2 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. Also see Note 7 to the financial statements of Georgia Power under “Commitments – Purchased Power Commitments” in Item 8 herein for additional information.

Titles to Property

The traditional 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 pursuant to pollution control revenue bonds of Alabama Power and Gulf Power on specific pollution control facilities. See Note 6 to the financial statements of Southern Company, Alabama Power, and Gulf Power 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 traditional 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.

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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(United States District Court for the Northern District of Georgia)

See Note 3 to the financial statements of Southern Company and each traditional operating company under “Environmental Matters – New Source Review Actions” in Item 8 herein for information.

(2) Environmental Remediation

See Note 3 to the financial statements of Southern Company, Georgia Power, Gulf Power, and Mississippi Power under “Environmental Matters – Environmental Remediation” and Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 herein for information related to environmental remediation.

(3) Right of Way Litigation

See Note 3 to the financial statements of Southern Company and Mississippi Power under “Right of Way Litigation” in Item 8 herein for information.

See Note 3 to the financial statements of each registrant 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, Gulf Power, Mississippi Power, and SouthernPower

None.

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EXECUTIVE OFFICERS OF SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2009.

David M. Ratcliffe

Chairman, President, Chief Executive Officer, and Director
Age 61

Elected in 1999. President since April 2004; Chairman and Chief Executive Officer since July 2004.

W. Paul Bowers

Executive Vice President and Chief Financial Officer
Age 53

Elected in 2001. Executive Vice President and Chief Financial Officer since February 2008 and Executive Vice President since May 2007. Previously served as President of Southern Company Generation, a business unit of Southern Company, and Executive Vice President of SCS from May 2001 through January 2008; and President and Chief Executive Officer of Southern Power from May 2001 through March 2005.

Thomas A. Fanning

Executive Vice President and Chief Operating Officer
Age 52

Elected in 2003. Executive Vice President and Chief Operating Officer since February 2008. Previously served as Executive Vice President and Chief Financial Officer from May 2007 through January 2008 and Executive Vice President, Chief Financial Officer, and Treasurer from April 2003 to May 2007.

Michael D. Garrett

Executive Vice President
Age 60

Elected in 2004. Executive Vice President since January 2004. He also serves as Chief Executive Officer, President, and Director of Georgia Power since April 2004.

G. Edison Holland, Jr.

Executive Vice President, General Counsel, and Secretary
Age 57

Elected in 2001. Executive Vice President and General Counsel since April 2001.

C. Alan Martin

Executive Vice President
Age 61

Elected in 2008. Executive Vice President since February 2008. He also serves as President and Chief Executive Officer of SCS since February 2008. Previously served as Executive Vice President of the Customer Service Organization at Alabama Power from May 2001 through January 2008.

Charles D. McCrary

Executive Vice President
Age 58

Elected in 1998. Executive Vice President since February 2002. He also serves as Chief Executive Officer, President, and Director of Alabama Power since October 2001.

I-33

James H. Miller, III

President and Chief Executive Officer of Southern Nuclear
Age 60

Elected in 2008. President and Chief Executive Officer of Southern Nuclear since August 27, 2008. Previously served as Senior Vice President and General Counsel of Georgia Power from March 2004 through August 2008.

Susan N. Story

President and Chief Executive Officer of Gulf Power
Age 49

Elected in 2003. President and Chief Executive Officer of Gulf Power since April 2003.

Anthony J. Topazi

President and Chief Executive Officer of Mississippi Power
Age 59

Elected in 2003. President and Chief Executive Officer of Mississippi Power since January 2004.

Christopher C. Womack

Executive Vice President
Age 51

Elected in 2008. Executive Vice President and President of External Affairs since January 1, 2009. Previously served as Executive Vice President of External Affairs of Georgia Power from March 2006 through December 2008 and Senior Vice President of Fossil and Hydro Generation and Senior Production Officer of Georgia Power from December 2001 to February 2006.

The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 27, 2009) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified.

I-34

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, 2009.

Charles D. McCrary

President, Chief Executive Officer, and Director
Age 58

Elected in 2001. President, Chief Executive Officer, and Director since October 2001; Executive Vice President of Southern Company since February 2002.

Art P. Beattie

Executive Vice President, Chief Financial Officer, and Treasurer
Age 55

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.

Mark A. Crosswhite

Executive Vice President
Age 47

Elected in 2008. Executive Vice President of External Affairs since February 1, 2008. Previously served as Senior Vice President and Counsel of Alabama Power from July 2006 through January 2008; Senior Vice President, General Counsel, and Assistant Secretary of Southern Power from March 2004 through January 2005; and Vice President of SCS from March 2004 through January 2008.

Steven R. Spencer

Executive Vice President
Age 54

Elected in 2001. Executive Vice President of the Customer Service Organization since February 1, 2008. Previously served as Executive Vice President of External Affairs from 2001 through January 2008.

Jerry L. Stewart

Senior Vice President
Age 60

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 meeting of the directors held on April 24, 2009 for one year or until their successors are elected and have qualified.

I-35

EXECUTIVE OFFICERS OF GEORGIA POWER

(Identification of executive officers of Georgia Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2009.

Michael D. Garrett

President, Chief Executive Officer, and Director
Age 60

Elected in 2003. President, Chief Executive Officer, and Director of Georgia Power since April 2004.

Mickey A. Brown

Executive Vice President
Age 62

Elected in 2001. Executive Vice President of the Customer Service Organization since January 2005.

Ronnie R. Labrato

Executive Vice President, Chief Financial Officer, and Treasurer
Age 56

Elected in 2009. Executive Vice President, Chief Financial Officer, and Treasurer since April 2009. Previously served as Vice President of Internal Auditing at SCS from April 2008 to March 2009 and Vice President and Chief Financial Officer of Gulf Power from July 2001 to March 2008.

Joseph A. Miller

Executive Vice President
Age 48

Elected in 2009. Executive Vice President of Nuclear Development since May 2009. Also serves as Executive Vice President of Nuclear Development at Southern Nuclear since February 2006. Previously served as Vice President of Government Relations at SCS from May 1999 to January 2006.

W. Craig Barrs

Executive Vice President
Age 52

Elected in 2008. Executive Vice President of External Affairs since January 2010. Previously served as Senior Vice President of External Affairs from January 2009 to January 2010, Vice President of Governmental and Regulatory Affairs from April 2008 to December 2008, Vice President of the Coastal Region from August 2006 to March 2008, President and Chief Executive Officer of Savannah Electric and Power Company from January 2006 until its merger with and into Georgia Power which was completed in July 2006, and Vice President of Community and Economic Development from November 2002 to December 2005.

Douglas E. Jones

Senior Vice President
Age 51

Elected in 2005. Senior Vice President of Fossil and Hydro Generation since March 2006. Previously served as Senior Vice President of Customer Service and Sales from January 2005 to February 2006 and Executive Vice President of Southern Power from January 2004 to January 2005.

Thomas P. Bishop

Senior Vice President, Chief Compliance Officer, and General Counsel
Age 49

Elected in 2008. Senior Vice President, Chief Compliance Officer, and General Counsel since September 2008. Previously served as Vice President and Associate General Counsel for SCS from July 2004 to September 2008.

The officers of Georgia Power were elected for a term running from the meeting of the directors held on May 20, 2009 for one year or until their successors are elected and have qualified.

I-36

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, 2009.

Anthony J. Topazi

President, Chief Executive Officer, and Director
Age 59

Elected in 2003. President, Chief Executive Officer, and Director since January 1, 2004.

Thomas O. Anderson, IV

Vice President
Age 50

Elected in 2009. Vice President of Generation Development since July 2009. Previously served as Project Director, Mississippi Power Generation Development from March 2008 to July 2009; Project Manager, Southern Power Generation from June 2007 to March 2008; and Generation Development Manager, SCS Generation Development from September 1998 to June 2007.

John W. Atherton

Vice President
Age 49

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.

Kimberly D. Flowers

Vice President
Age 45

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.

Donald R. Horsley

Vice President
Age 55

Elected in 2006. Vice President of Customer Services and Retail Marketing since April 2006. Previously served as Vice President of Transmission at Alabama Power from March 2005 to March 2006 and Manager, Transmission Lines at Alabama Power from February 2001 to March 2005.

Frances Turnage

Vice President, Treasurer, and
Chief Financial Officer

Age 61

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 meeting of the directors held on April 8, 2009 for one year or until their successors are elected and have qualified.

I-37

PART II

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

(a)(1) 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. The high and low stock prices as reported on the New York Stock Exchange for each quarter of the past two years were as follows:

	High		Low
2009
First Quarter	$	37.62	$	26.48
Second Quarter		32.05		27.19
Third Quarter		32.67		30.27
Fourth Quarter		34.47		30.89
2008
First Quarter	$	40.60	$	33.71
Second Quarter		37.81		34.28
Third Quarter		40.00		34.46
Fourth Quarter		38.18		29.82

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

(a)(2) Number of Southern Company’s common stockholders of record at January 31, 2010:      92,374

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

(a)(3) 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 traditional operating companies to their stockholder(s) for the past two years were as follows:

Registrant	Quarter	2009		2008
		(in thousands)
Southern Company	First	$	326,780	$	307,960
	Second		343,446		322,634
	Third		348,702		323,844
	Fourth		350,538		325,681
Alabama Power	First		130,700		122,825
	Second		130,700		122,825
	Third		130,700		122,825
	Fourth		130,700		122,825
Georgia Power	First		184,725		180,300
	Second		184,725		180,300
	Third		184,725		180,300
	Fourth		184,725		180,300
Gulf Power	First		22,350		20,425
	Second		22,300		20,425
	Third		22,325		20,425
	Fourth		22,325		20,425
Mississippi Power	First		17,125		17,100
	Second		17,125		17,100
	Third		17,125		17,100
	Fourth		17,125		17,100

II-1

In 2009 and 2008, Southern Power paid dividends to Southern Company as follows:

Registrant	Quarter	2009		2008
			(in millions)
Southern Power	First	$	26.525	$	23.63
	Second		26.525		23.63
	Third		26.525		23.63
	Fourth		26.525		23.63

The dividend paid per share of Southern Company’s common stock was 40.25¢ for the first quarter of 2008 and 42¢ for the second, third, and fourth quarters of 2008. In 2009, Southern Company paid a dividend per share of 42¢ in the first quarter of 2009 and 43.75¢ for the second, third, and fourth quarters of 2009.

The traditional operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Southern Power’s credit facility and senior note indenture contain potential limitations on the payment of common stock dividends. At December 31, 2009, 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” and Note 6 to the financial statements of Southern Power under “Dividend Restrictions” in Item 8 herein for additional information regarding these restrictions.

(a)(4) Securities authorized for issuance under equity compensation plans.

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters under the heading “Equity Compensation Plan Information” herein.

(b) Use of Proceeds

Not applicable.

(c) Issuer Purchases of Equity Securities

None.

Item 6. SELECTED FINANCIAL DATA

Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-95 and II-96.

Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-167 and II-168.

Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-242 and II-243.

Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-308 and II-309.

Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-382 and II-383.

Southern Power. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at page II-430.

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-39.

II-2

Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-100 through II-122.

Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-172 through II-195.

Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-247 through II-267.

Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-313 through II-338.

Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” contained herein at pages II-387 through II-406.

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 10 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 9 to the financial statements of Gulf Power and Mississippi Power, and Note 8 to the financial statements of Southern Power in Item 8 herein.

II-3

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2009 FINANCIAL STATEMENTS

	Page
The Southern Company and Subsidiary Companies:
Management’s Report on Internal Control Over Financial Reporting	II-9
Report of Independent Registered Public Accounting Firm	II-10
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-40
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-41
Consolidated Balance Sheets at December 31, 2009 and 2008	II-42
Consolidated Statements of Capitalization at December 31, 2009 and 2008	II-44
Consolidated Statements of Common Stockholders’ Equity for the Years Ended December 31, 2009, 2008, and 2007	II-46
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-47
Notes to Financial Statements	II-48
Alabama Power:
Management’s Report on Internal Control Over Financial Reporting	II-98
Report of Independent Registered Public Accounting Firm	II-99
Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-123
Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-124
Balance Sheets at December 31, 2009 and 2008	II-125
Statements of Capitalization at December 31, 2009 and 2008	II-127
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007	II-129
Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-130
Notes to Financial Statements	II-131
Georgia Power:
Management’s Report on Internal Control Over Financial Reporting	II-170
Report of Independent Registered Public Accounting Firm	II-171
Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-196
Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-197
Balance Sheets at December 31, 2009 and 2008	II-198
Statements of Capitalization at December 31, 2009 and 2008	II-200
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007	II-201
Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-202
Notes to Financial Statements	II-203
Gulf Power:
Management’s Report on Internal Control Over Financial Reporting	II-245
Report of Independent Registered Public Accounting Firm	II-246
Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-268
Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-269
Balance Sheets at December 31, 2009 and 2008	II-270
Statements of Capitalization at December 31, 2009 and 2008	II-272
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007	II-273
Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-274
Notes to Financial Statements	II-275

II-4

	Page
Mississippi Power:
Management’s Report on Internal Control Over Financial Reporting	II-311
Report of Independent Registered Public Accounting Firm	II-312
Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-339
Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-340
Balance Sheets at December 31, 2009 and 2008	II-341
Statements of Capitalization at December 31, 2009 and 2008	II-343
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007	II-344
Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-345
Notes to Financial Statements	II-346
Southern Power and Subsidiary Companies:
Management’s Report on Internal Control Over Financial Reporting	II-385
Report of Independent Registered Public Accounting Firm	II-386
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008, and 2007	II-407
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007	II-408
Consolidated Balance Sheets at December 31, 2009 and 2008	II-409
Consolidated Statements of Common Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007	II-411
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2008, and 2007	II-412
Notes to Financial Statements	II-413

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 conducted an evaluation under the supervision and with the participation of Southern 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 this evaluation, the Chief Executive Officer and the Chief Financial Officer 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.

Southern Company’s Management’s Report on Internal Control Over Financial Reporting is included on page II-9 of this Form 10-K.

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

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

     (c) Changes in internal controls.

There have been no changes in Southern Company’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 2009 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting other than as described in the next paragraph.

In October 2009, Georgia Power implemented a new general ledger system. The implementation of this system provides additional operational and internal control benefits including system security and automation of previously manual controls. This process improvement initiative was not in response to an identified internal control deficiency.

Item 9A(T). CONTROLS AND PROCEDURES

Disclosure Controls And Procedures.

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

Internal Control Over Financial Reporting.

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

Alabama Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-98 of this Form 10-K.

Georgia Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-170 of this Form 10-K.

Gulf Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-245 of this Form 10-K.

II-6

Mississippi Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-311 of this Form 10-K.

Southern Power’s Management’s Report on Internal Control Over Financial Reporting is included on page II-385 of this Form 10-K.

(b) Changes in internal controls.

There have been no changes in Alabama 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 2009 that have materially affected or are reasonably likely to materially affect Alabama Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

There have been no changes in Georgia 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 2009 that have materially affected or are reasonably likely to materially affect Georgia Power’s internal control over financial reporting, other than as described in the next sentence. In October 2009, Georgia Power implemented a new general ledger system. The implementation of this system provides additional operational and internal control benefits including system security and automation of previously manual controls. This process improvement initiative was not in response to an identified internal control deficiency.

Item 9B. OTHER INFORMATION

Georgia Power

On February 23, 2010, Georgia Power, acting for itself and as agent for OPC, MEAG Power, and Dalton (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster (collectively, Consortium) entered into an amendment (Amendment) to the Engineering, Procurement, and Construction Agreement, dated as of April 8, 2008 (Agreement), between the Owners and the Consortium, relating to Plant Vogtle Units 3 and 4. Under the Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalation and adjustments, including certain index-based adjustments, as well as adjustments for change orders, and performance bonuses. The Amendment, which is subject to the approval of the Georgia PSC, replaces certain of the index-based adjustments to the purchase price with fixed escalation amounts.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 herein and Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 herein for information regarding Georgia Power’s construction of Plant Vogtle Units 3 and 4.

II-7

THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

FINANCIAL SECTION

II-8

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company and Subsidiary Companies 2009 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. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2009.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2009. Deloitte & Touche LLP’s report on 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/ W. Paul Bowers

W. Paul Bowers
Executive Vice President and Chief Financial Officer

February 25, 2010

II-9

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, 2009 and 2008, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, 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 these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (page II-9). Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide 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, the consolidated financial statements (pages II-40 to II-93) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

II-10

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2009 Annual Report

OVERVIEW

Business Activities

The primary business of Southern Company (the Company) is electricity sales in the Southeast by the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages 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 traditional operating companies’ ability to maintain a constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of rising costs. Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.

Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. The Company continues to face regulatory challenges related to transmission issues at the national level. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

Southern Company’s other business activities include investments in leveraged lease projects, renewable energy projects, and telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective energy to more than four 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), excluding the MC Asset Recovery, LLC (MC Asset Recovery) litigation settlement discussed below. 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 and nuclear 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. The fossil/hydro 2009 Peak Season EFOR of 1.44% was better than the target. The nuclear 2009 Peak Season EFOR of 2.61% was slightly better than the target. 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 performance for 2009 was better than the target for these reliability measures.

Southern Company entered into a settlement agreement with MC Asset Recovery to resolve a complaint alleging that Southern Company caused Mirant Corporation (Mirant) to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off of Mirant in 2001. Pursuant to the settlement, Southern Company recorded a charge of $202 million in 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. Southern Company management uses the non-GAAP (defined below) measure of EPS, excluding the MC Asset Recovery litigation settlement, to evaluate the performance of Southern Company’s ongoing business activities. Southern Company believes the presentation of this non-GAAP measure of earnings and EPS excluding the MC Asset Recovery litigation settlement is useful for investors because it provides earnings information that is consistent with the historical and ongoing business activities of the Company. The presentation of this information is not meant to be considered a substitute for financial measures prepared in accordance with generally accepted accounting principles (GAAP).

II-11

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Southern Company’s 2009 results compared with its targets for some of these key indicators are reflected in the following chart:

	2009 Target	2009 Actual
Key Performance Indicator	Performance	Performance
	Top quartile in
Customer Satisfaction	customer surveys	Top quartile
Peak Season EFOR — fossil/hydro	2.75% or less		1.44	%
Peak Season EFOR — nuclear	2.75% or less		2.61	%
Basic EPS	$2.30 — $2.45	$	2.07
EPS, excluding the MC Asset Recovery litigation settlement	—	$	2.32

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2009 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 net income after dividends on preferred and preference stock of subsidiaries was $1.64 billion in 2009, a decrease of $99 million from the prior year. This decrease was primarily the result of a litigation settlement with MC Asset Recovery, a decrease in revenues from lower kilowatt-hour (KWH) demand across all customer classes, a decrease in revenues from market-response rates to large commercial and industrial customers, higher depreciation and amortization, higher interest expense, and unfavorable weather. The 2009 decrease was partially offset by an increase in revenues from customer charges at Alabama Power, increased recognition of environmental compliance cost recovery (ECCR) revenues at Georgia Power in accordance with its retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan), lower operations and maintenance expenses, an increase in allowance for funds used during construction (AFUDC) equity, which is not taxable, a 2008 charge related to the tax treatment of leveraged lease investments, and a gain on the early retirement of two international leveraged lease investments. Net income after dividends on preferred and preference stock of subsidiaries was $1.74 billion in 2008 and $1.73 billion in 2007. Basic EPS was $2.07 in 2009, $2.26 in 2008, and $2.29 in 2007. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.06 in 2009, $2.25 in 2008, and $2.28 in 2007.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.7325 in 2009, $1.6625 in 2008, and $1.595 in 2007. In January 2010, Southern Company declared a quarterly dividend of 43.75 cents per share. This is the 249th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company targets a dividend payout ratio of approximately 65% to 70% of net income. For 2009, the actual payout ratio was 83.3% while the payout ratio of net income excluding the MC Asset Recovery litigation settlement was 74.2%.

II-12

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

RESULTS OF OPERATIONS

Electricity Business

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

			Increase (Decrease)
	Amount		from Prior Year
	2009		2009			2008		2007
	(in millions)
Electric operating revenues	$	15,642	$	(1,358	)	$	1,860	$	1,052
Fuel		5,952		(865	)		973		701
Purchased power		474		(341	)		300		(28	)
Other operations and maintenance		3,401		(183	)		111		183
Depreciation and amortization		1,476		62			199		51
Taxes other than income taxes		816		22			56		23
Total electric operating expenses		12,119		(1,305	)		1,639		930
Operating income		3,523		(53	)		221		122
Other income (expense), net		199		53			26		66
Interest expense, net of amounts capitalized		834		61			10		46
Income taxes		988		(49	)		87		1
Net income		1,900		(12	)		150		141
Dividends on preferred and preference stock of subsidiaries		65		—			17		13
Net income after dividends on preferred and preference stock of subsidiaries	$	1,835	$	(12	)	$	133	$	128

Electric Operating Revenues

Details of electric operating revenues were as follows:

	Amount
	2009			2008			2007
	(in millions)
Retail — prior year	$	14,055		$	12,639		$	11,801
Estimated change in —
Rates and pricing		144			668			161
Sales growth (decline)		(208	)		—			60
Weather		(21	)		(106	)		54
Fuel and other cost recovery		(663	)		854			563
Retail — current year		13,307			14,055			12,639
Wholesale revenues		1,802			2,400			1,988
Other electric operating revenues		533			545			513
Electric operating revenues	$	15,642		$	17,000		$	15,140
Percent change		(8.0	%)		12.3	%		7.5	%

II-13

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Retail revenues decreased $748 million, increased $1.4 billion, and increased $838 million in 2009, 2008, and 2007, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 2009 was primarily due to an increase in revenues from customer charges at Alabama Power and increased recognition of ECCR revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers at Georgia Power. The 2008 increase in rates and pricing when compared to the prior year was primarily due to Alabama Power’s increase under its Rate Stabilization and Equalization Plan (Rate RSE), as ordered by the Alabama Public Service Commission (PSC), and Georgia Power’s increase under its 2007 Retail Rate Plan, as ordered by the Georgia PSC. Also contributing to the 2008 increase was an increase in revenues from market-response rates to large commercial and industrial customers. The 2007 increase in rates and pricing when compared to the prior year was primarily due to Alabama Power’s increase under its Rate RSE, as ordered by the Alabama PSC. Partially offsetting the 2007 increase was a decrease in revenues from market-response rates to large commercial and industrial customers. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and PPAs.

Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy.

In 2009, wholesale revenues decreased $598 million. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $603 million in 2009. Excluding wholesale fuel revenues, wholesale revenues increased $5 million primarily due to additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower gas prices and reduced margins on short-term opportunity sales.

In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the average cost of fuel per net KWH generated, as well as revenues resulting from new and existing PPAs and revenues derived from contracts for Southern Power’s Plant Oleander Unit 5 and Plant Franklin Unit 3 placed in operation in December 2007 and June 2008, respectively. The 2008 increase was partially offset by a decrease in short-term opportunity sales and weather-related generation load reductions.

In 2007, wholesale revenues increased $166 million primarily as a result of a 9.5% increase in the average cost of fuel per net KWH generated. Excluding fuel, wholesale revenues were flat when compared to the prior year.

Revenues associated with PPAs and opportunity sales were as follows:

	2009		2008		2007
	(in millions)
Other power sales —
Capacity and other	$	575	$	538	$	533
Energy		735		1,319		989
Total	$	1,310	$	1,857	$	1,522

II-14

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect the recovery of fixed costs and a return on investment. Unit power KWH sales decreased 7.5%, 2.1%, and 0.8% in 2009, 2008, and 2007, respectively. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales contracts, influence changes in these sales. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Alabama Power” herein for additional information regarding the termination of certain unit power sales contracts in 2010. 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 sales contracts were as follows:

	2009		2008		2007
	(in millions)
Unit power sales —
Capacity	$	225	$	223	$	202
Energy		267		320		264
Total	$	492	$	543	$	466

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2009 and the percent change by year were as follows:

	KWHs		Percent Change
	2009		2009			2008			2007
	(in billions)
Residential		51.7		(1.1	)%		(2.0	)%		1.8	%
Commercial		53.5		(1.7	)		(0.4	)		3.2
Industrial		46.4		(11.8	)		(3.7	)		(0.7	)
Other		1.0		2.0			(2.9	)		4.4
Total retail		152.6		(4.8	)		(2.1	)		1.4
Wholesale		33.5		(14.9	)		(3.4	)		5.9
Total energy sales		186.1		(6.8	)		(2.3	)		2.3

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales decreased 7.7 billion KWHs in 2009 primarily as a result of lower usage by industrial customers due to the recessionary economy. Reduced demand in the primary metal, chemical, and textile sectors, as well as the stone, clay, and glass sector, contributed most significantly to the decrease in industrial KWH sales. Unfavorable weather also contributed to lower KWH sales across all customer classes. The number of customers in 2009 was flat compared to 2008. Retail energy sales in 2008 decreased 3.4 billion KWHs as a result of a 1.4% decrease in electricity usage mainly due to a slowing economy that worsened during the fourth quarter. The 2008 decrease in residential sales resulted primarily from lower home occupancy rates in Southern Company’s service area when compared to 2007. Throughout the year, reduced demand in the textile sector, the lumber sector, and the stone, clay, and glass sector contributed to the decrease in 2008 industrial sales. Additional weakness in the fourth quarter 2008 affected all major industrial segments. Significantly less favorable weather in 2008 when compared to 2007 also contributed to the 2008 decrease in retail energy sales. These decreases were partially offset by customer growth of 0.6%. Retail energy sales in 2007 increased 2.3 billion KWHs as a result of 1.3% customer growth and favorable weather in 2007 when compared to 2006. The 2007 decrease in industrial sales primarily resulted from reduced demand and closures within the textile sector, as well as decreased demand in the primary metals sector and the stone, clay, and glass sector.

Wholesale energy sales decreased by 5.9 billion KWHs in 2009, decreased by 1.4 billion KWHs in 2008, and increased by 2.3 billion KWHs in 2007. The decrease in wholesale energy sales in 2009 was primarily related to fewer short-term opportunity sales driven by lower gas prices and fewer uncontracted generating units at Southern Power available to sell electricity on the wholesale market. The decrease in wholesale energy sales in 2008 was primarily related to longer planned maintenance outages at a fossil unit in 2008 as compared to 2007 which reduced the availability of this unit for wholesale sales. Lower short-term opportunity sales primarily related to higher coal prices also contributed to the 2008 decrease. These decreases were partially offset by Plant Oleander Unit 5 and Plant Franklin Unit 3 being placed in operation in December 2007 and June 2008, respectively. The increase in wholesale energy sales in 2007 was primarily related to new PPAs acquired by Southern Company through the acquisition of Plant Rowan in September 2006, as well as new contracts with EnergyUnited Electric Membership Corporation that commenced in September 2006 and January 2007. An increase in KWH sales under existing PPAs also contributed to the 2007 increase.

II-15

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

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. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market. Details of electricity generated and purchased by the electric utilities were as follows:

	2009		2008		2007
Total generation(billions of KWHs)		187		198		206
Total purchased power(billions of KWHs)		8		11		8
Sources of generation(percent)—
Coal		57		68		70
Nuclear		16		15		14
Gas		23		16		15
Hydro		4		1		1
Cost of fuel, generated(cents per net KWH)—
Coal		3.70		3.27		2.61
Nuclear		0.55		0.50		0.50
Gas		4.58		7.58		6.64
Average cost of fuel, generated(cents per net KWH)*		3.38		3.52		2.89
Average cost of purchased power(cents per net KWH)		6.37		7.85		7.20

* Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

In 2009, fuel and purchased power expenses were $6.4 billion, a decrease of $1.2 billion or 15.8% below 2008 costs. This decrease was primarily the result of an $839 million decrease related to the total KWHs generated and purchased due primarily to lower customer demand. Also contributing to this decrease was a $367 million reduction in the average cost of fuel and purchased power resulting primarily from a 39.6% decrease in the cost of gas per KWH generated.

In 2008, fuel and purchased power expenses were $7.6 billion, an increase of $1.3 billion or 20.0% above 2007 costs. This increase was primarily the result of a $1.3 billion net increase in the average cost of fuel and purchased power partially resulting from a 25.3% increase in the cost of coal per net KWH generated and a 14.2% increase in the cost of gas per net KWH generated.

In 2007, fuel and purchased power expenses were $6.4 billion, an increase of $673 million or 11.8% above 2006 costs. This increase was primarily the result of a $543 million net increase in the average cost of fuel and purchased power partially resulting from a 51.4% decrease in hydro generation as a result of a severe drought. Also contributing to this increase was a $130 million increase related to higher net KWHs generated and purchased.

Coal prices continued to be influenced by worldwide demand from developing countries, as well as increased mining and fuel transportation costs. While coal prices reached unprecedented high levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices did not fully offset the higher priced coal already in inventory and under long-term contract. Demand for natural gas in the United States also was affected by the recessionary economy leading to significantly lower natural gas prices. During 2009, uranium prices continued to moderate from the highs set during 2007. Worldwide production levels increased in 2009; however, secondary supplies and inventories were still required to meet worldwide reactor demand.

Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the traditional operating companies’ fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses were $3.4 billion, $3.6 billion, and $3.5 billion, decreasing $183 million, increasing $111 million, and increasing $183 million in 2009, 2008, and 2007, respectively. Discussion of significant variances for components of other operations and maintenance expenses follows.

II-16

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Other production expenses at fossil, hydro, and nuclear plants decreased $70 million, increased $63 million, and increased $128 million in 2009, 2008, and 2007, respectively. Production expenses fluctuate from year to year due to variations in outage schedules and normal changes in the cost of labor and materials. Other production costs decreased in 2009 mainly due to a $104 million decrease related to less planned spending on outages and maintenance, as well as other cost containment activities, which were the results of efforts to offset the effects of the recessionary economy. The 2009 decrease was partially offset by a $6 million increase related to new facilities, a $5 million loss on the transfer of Southern Power’s Plant Desoto in 2009, a $6 million gain recognized in 2008 by Southern Power on the sale of an undeveloped tract of land to the Orlando Utilities Commission (OUC), and a $17 million increase in nuclear refueling costs. See Note 1 to the financial statements under “Property, Plant, and Equipment” for additional information regarding nuclear refueling costs. Other production expenses increased in 2008 primarily due to a $64 million increase related to expenses incurred for maintenance outages at generating units and a $30 million increase related to labor and materials expenses, partially offset by a $15 million decrease in nuclear refueling costs. The 2008 increase was also partially offset by a $24 million decrease related to new facilities, mainly lower costs associated with the 2007 write-off of Southern Power’s integrated coal gasification combined cycle (IGCC) project with the OUC. Other production expenses increased in 2007 primarily due to a $40 million increase related to expenses incurred for maintenance outages at generating units and a $29 million increase related to new facilities, mainly costs associated with the write-off of Southern Power’s IGCC project and the acquisitions of Plants DeSoto and Rowan by Southern Power in June and September 2006, respectively. A $25 million increase related to labor and materials expenses and a $22 million increase in nuclear refueling costs also contributed to the 2007 increase.

Transmission and distribution expenses decreased $41 million, increased $4 million, and increased $21 million in 2009, 2008, and 2007, respectively. Transmission and distribution expenses fluctuate from year to year due to variations in maintenance schedules and normal changes in the cost of labor and materials. Transmission and distribution expenses decreased in 2009 primarily related to lower planned spending, as well as other cost containment activities. The 2008 increase in transmission and distribution expenses was not material when compared to the prior year. Transmission and distribution expenses increased in 2007 primarily as a result of increases in labor and materials costs and maintenance associated with additional investment to meet customer growth.

Customer sales and service expenses decreased $42 million, increased $32 million, and increased $7 million in 2009, 2008, and 2007, respectively. Customer sales and service expenses decreased in 2009 primarily as a result of a $12 million decrease in customer service expenses, an $8 million decrease in meter reading expenses, a $10 million decrease in sales expenses, and a $7 million decrease in customer records related expenses. The 2008 increase in customer sales and service expenses was primarily a result of an increase in customer service expenses, including a $13 million increase in uncollectible accounts expense, a $9 million increase in meter reading expenses, and an $8 million increase for customer records and collections. The 2007 increase in customer sales and service expenses was not material when compared to the prior year.

Administrative and general expenses decreased $30 million, increased $12 million, and increased $27 million in 2009, 2008, and 2007, respectively. The 2009 decrease in administrative and general expenses was primarily the result of cost containment activities which were the results of efforts to offset the effects of the recessionary economy. The 2008 increase in administrative and general expenses was not material when compared to 2007. Administrative and general expenses increased in 2007 primarily as a result of a $16 million increase in legal costs and expenses associated with an increase in employees. Also contributing to the 2007 increase was a $14 million increase in accrued expenses for the litigation and workers’ compensation reserve, partially offset by an $8 million decrease in property damage expense.

Depreciation and Amortization

Depreciation and amortization increased $62 million in 2009 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and the completion of Southern Power’s Plant Franklin Unit 3, as well as an increase in depreciation rates at Southern Power. Partially offsetting the 2009 increase was a decrease associated with the amortization of the regulatory liability related to the cost of removal obligations as authorized by the Georgia PSC. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Cost of Removal” for additional information regarding Georgia Power’s cost of removal amortization.

Depreciation and amortization increased $199 million in 2008 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power and generation projects at Georgia Power. An increase in depreciation rates at Georgia Power and Southern Power also contributed to the 2008 increase, as well as the expiration of a rate order previously allowing Georgia Power to levelize certain purchased power capacity costs and the completion of Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Depreciation and amortization increased $51 million in 2007 primarily as a result of an increase in plant in service related to environmental, transmission, and distribution projects mainly at Alabama Power and Georgia Power. An increase in the amortization expense of a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity also contributed to the 2007 increase. Partially offsetting the 2007 increase was a reduction in amortization expense due to a Georgia Power regulatory liability related to the levelization of certain purchased power capacity costs as ordered by the Georgia PSC under the terms of the retail rate order effective January 1, 2005. See Note 1 to the financial statements under “Depreciation and Amortization” for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $22 million in 2009 primarily as a result of increases in the bases of state and municipal public utility license taxes at Alabama Power and an increase in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from energy sales. Taxes other than income taxes increased $56 million in 2008 primarily as a result of increases in franchise fees and municipal gross receipt taxes associated with increases in revenues from energy sales, as well as increases in property taxes associated with property tax actualizations and additional plant in service. Taxes other than income taxes increased $23 million in 2007 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales, partially offset by a decrease in property taxes resulting from the resolution of a dispute with Monroe County, Georgia.

Other Income (Expense), Net

Other income (expense), net increased $53 million in 2009 primarily due to an increase in AFUDC equity as a result of environmental projects at Alabama Power and Gulf Power and additional investments in transmission and distribution projects at Alabama Power. In addition, during 2009, Southern Power recognized a $13 million profit under a construction contract with the OUC whereby Southern Power provided engineering, procurement, and construction services to build a combined cycle unit. Other income (expense), net increased $26 million in 2008 primarily as a result of an increase in AFUDC equity related to additional investments in environmental equipment at generating plants at Alabama Power, Georgia Power, and Gulf Power, as well as additional investments in transmission and distribution projects mainly at Alabama Power and Georgia Power. Other income (expense), net increased $66 million in 2007 primarily as a result of an increase in AFUDC equity related to additional investments in environmental equipment at generating plants and transmission and distribution projects mainly at Alabama Power and Georgia Power.

Interest Expense, Net of Amounts Capitalized

Total interest charges and other financing costs increased by $61 million in 2009 primarily as a result of a $100 million increase associated with $1.4 billion in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Also contributing to the 2009 increase was $16 million in other interest costs. The 2009 increase was partially offset by $42 million related to lower average interest rates on existing variable rate debt and $13 million of additional capitalized interest as compared to 2008.

Total interest charges and other financing costs increased by $10 million in 2008 primarily as a result of a $65 million increase associated with $1.8 billion in additional debt outstanding at December 31, 2008 compared to December 31, 2007. Also contributing to the 2008 increase was $5 million in other interest costs. The 2008 increase was partially offset by $55 million related to lower average interest rates on existing variable rate debt and $7 million of additional capitalized interest as compared to 2007.

Total interest charges and other financing costs increased by $46 million in 2007 primarily as a result of a $59 million increase associated with $703 million in additional debt outstanding at December 31, 2007 compared to December 31, 2006 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the 2007 increase was $7 million related to higher average interest rates on existing variable rate debt and $19 million in other interest costs. The 2007 increase was partially offset by $38 million of additional capitalized interest as compared to 2006.

Income Taxes

Income taxes decreased $49 million in 2009 primarily due to lower pre-tax earnings as compared to 2008, an increase in AFUDC equity, which is not taxable, and an increase in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

II-18

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Income taxes increased $87 million in 2008 primarily due to higher pre-tax earnings as compared to 2007 and a 2007 deduction for a Georgia Power land donation. The 2008 increase was partially offset by an increase in AFUDC equity, which is not taxable.

Income taxes were relatively flat in 2007 as higher pre-tax earnings as compared to 2006 were largely offset due to a deduction for a Georgia Power land donation; an increase in AFUDC equity, which is not taxable; and an increase in the Section 199 production activities deduction.

Dividends on Preferred and Preference Stock of Subsidiaries

Dividends on preferred and preference stock of subsidiaries for 2009 were flat compared to the prior year.

Dividends on preferred and preference stock of subsidiaries increased $17 million in 2008 primarily as a result of issuances of $320 million and $150 million of preference stock in the third and fourth quarters of 2007, respectively, partially offset by the redemption of $125 million of preferred stock in January 2008.

Dividends on preferred and preference stock of subsidiaries increased $13 million in 2007 primarily as a result of a $470 million increase associated with additional preference stock outstanding at December 31, 2007 compared to December 31, 2006.

Other Business Activities

Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in leveraged lease projects, and telecommunications. Southern Company’s investment in synthetic fuel projects ended at December 31, 2007. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various projects, including leveraged lease projects; SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast.

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

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008			2007
	(in millions)
Operating revenues	$	101		$	(26	)	$	(86	)	$	(55	)
Other operations and maintenance		125			(40	)		(44	)		(29	)
MC Asset Recovery litigation settlement		202			202			—			—
Depreciation and amortization		27			(2	)		(1	)		(6	)
Taxes other than income taxes		2			(1	)		—			—
Total operating expenses		356			159			(45	)		(35	)
Operating income (loss)		(255	)		(185	)		(41	)		(20	)
Equity in income (losses) of unconsolidated subsidiaries		(1	)		(11	)		35			35
Leveraged lease income (losses)		40			125			(125	)		(29	)
Other income (expense), net		3			(8	)		(31	)		74
Interest expense		71			(22	)		(30	)		(26	)
Income taxes		(92	)		30			(7	)		53
Net income (loss)	$	(192	)	$	(87	)	$	(125	)	$	33

Operating Revenues

Southern Company’s non-electric operating revenues from these other businesses decreased $26 million in 2009 primarily as a result of a $25 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry. The $86 million decrease in 2008 primarily resulted from a $60 million decrease associated with Southern Company terminating its investment in synthetic fuel projects at December 31, 2007 and a $21 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to

II-19

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

increased competition in the industry. Also contributing to the 2008 decrease was a $5 million decrease in revenues from Southern Company’s energy-related services business. The $55 million decrease in 2007 primarily resulted from a $14 million decrease in fuel procurement service revenues following a contract termination, a $13 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry, and an $11 million decrease in revenues from Southern Company’s energy-related services business.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other businesses decreased $40 million in 2009 primarily as a result of a $15 million decrease in salary and wages, advertising, equipment, and network costs at SouthernLINC Wireless; a $10 million decrease in expenses associated with leveraged lease litigation costs; and a $6 million decrease in parent company expenses associated with the MC Asset Recovery litigation. Other operations and maintenance expenses decreased $44 million in 2008 primarily as a result of $11 million of lower coal expenses related to Southern Company terminating its investment in synthetic fuel projects at December 31, 2007; $9 million of lower sales expenses at SouthernLINC Wireless related to lower sales volume; and $5 million of lower parent company expenses related to advertising, litigation, and property insurance costs. Other operations and maintenance expenses decreased $29 million in 2007 primarily as a result of $11 million of lower production expenses related to the termination of Southern Company’s membership interest in one of the synthetic fuel entities and $8 million attributed to the wind-down of one of the Company’s energy-related services businesses.

MC Asset Recovery Litigation Settlement

On March 31, 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202 million and requires MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million, which was paid in the second quarter 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. On June 29, 2009, the case was dismissed with prejudice.

Equity in Income (Losses) of Unconsolidated Subsidiaries

Southern Company made investments in two synthetic fuel production facilities that generated operating losses. These investments allowed Southern Company to claim federal income tax credits that offset these operating losses and made the projects profitable. Equity in income (losses) of unconsolidated subsidiaries decreased $11 million in 2009 as a result of an $11 million gain recognized in 2008 related to the dissolution of a partnership that was associated with these synthetic fuel production facilities. Equity in income (losses) of unconsolidated subsidiaries increased $35 million in 2008 primarily as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. Equity in income (losses) of unconsolidated subsidiaries increased $35 million in 2007 primarily as a result of terminating Southern Company’s membership interest in one of the synthetic fuel entities which reduced the amount of the Company’s share of the losses and, therefore, the funding obligation for the year. Also contributing to the 2007 decrease were adjustments to the phase-out of the related federal income tax credits, partially offset by higher operating expenses due to idled production in 2006 and decreased production in 2007 in anticipation of exiting the business.

Leveraged Lease Income (Losses)

Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Leveraged lease income (losses) increased $125 million in 2009 primarily as a result of the application in 2008 of certain accounting standards related to leveraged leases, as well as a $26 million gain recorded in the second quarter 2009 associated with the early termination of two international leveraged lease investments. The proceeds from the termination were required to be used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss and partially offset the 2009 increase. Leveraged lease income (losses) decreased $125 million in 2008 as a result of Southern Company’s decision to participate in a settlement with the Internal Revenue Service (IRS) related to deductions for several sale-in-lease-out transactions and the resulting application of certain accounting standards related to leveraged leases. Leveraged lease income (losses) decreased $29 million in 2007 as a result of the adoption of certain accounting standards related to leveraged leases, as well as an expected decline in leveraged lease income over the terms of the leases.

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Southern Company and Subsidiary Companies 2009 Annual Report

Other Income (Expense), Net

The 2009 change in other income (expense), net for these other businesses when compared to the prior year was not material. Other income (expense), net decreased $31 million in 2008 primarily as a result of the 2007 gain on a derivative transaction in the synthetic fuel business which settled on December 31, 2007. Other income (expense), net increased $74 million in 2007 primarily as a result of a $60 million increase related to changes in the value of derivative transactions in the synthetic fuel business and a $16 million increase related to the 2006 impairment of investments in the synthetic fuel entities, partially offset by the release of $6 million in certain contractual obligations associated with these investments in 2006.

Interest Expense

Total interest charges and other financing costs for these other businesses decreased $22 million in 2009 primarily as a result of $26 million associated with lower average interest rates on existing variable rate debt and a $2 million decrease attributed to other interest charges. The 2009 decrease was partially offset by a $4 million increase associated with $63 million in additional debt outstanding at December 31, 2009 compared to December 31, 2008. Total interest charges and other financing costs decreased $30 million in 2008 primarily as a result of $29 million associated with lower average interest rates on existing variable rate debt and a $4 million decrease attributed to lower interest rates associated with new debt issued to replace maturing securities. At December 31, 2008, these other businesses had $92 million in additional debt outstanding compared to December 31, 2007. The 2008 decrease was partially offset by a $5 million increase in other interest costs. Total interest charges and other financing costs decreased by $26 million in 2007 primarily as a result of $16 million of losses on debt that was reacquired in 2006. Also contributing to the 2007 decrease was $97 million less debt outstanding at December 31, 2007 compared to December 31, 2006, lower interest rates associated with the issuance of new long-term debt, and a $4 million decrease in other interest costs.

Income Taxes

Income taxes for these other businesses increased $30 million in 2009 excluding the effects of the $202 million charge resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009. The 2009 increase was primarily due to the application in 2008 of certain accounting standards related to leveraged leases and income taxes. Partially offsetting this increase was lower tax expense associated with the early termination of two international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Leveraged Lease Income (Losses).” Income taxes decreased $7 million in 2008 primarily as a result of leveraged lease losses discussed previously under “Leveraged Lease Income (Losses),” partially offset by a $36 million decrease in net synthetic fuel tax credits as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. Income taxes increased $53 million in 2007 primarily as a result of a $30 million decrease in net synthetic fuel tax credits as a result of terminating Southern Company’s membership interest in one of the synthetic fuel entities in 2006 and increasing the synthetic fuel tax credit reserves due to an anticipated phase-out of synthetic fuel tax credits due to higher oil prices. See Note 5 to the financial statements under “Effective Tax Rate” for further information.

Effects of Inflation

The traditional operating companies are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company’s results of operations has not been substantial.

FUTURE EARNINGS POTENTIAL

General

The four traditional operating companies operate as vertically integrated utilities 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. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC). Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term capacity contracts, optimized by limited energy trading activities. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about regulatory matters.

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Southern Company and Subsidiary Companies 2009 Annual Report

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 traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Other major factors include the profitability of the competitive wholesale supply business and federal regulatory policy which may impact Southern Company’s level of participation in this market. Southern Company continues to face regulatory challenges related to transmission issues at the national level. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Recessionary conditions have negatively impacted sales for the traditional operating companies, particularly to industrial and commercial customers, and have negatively impacted wholesale capacity revenues at Southern Power. The timing and extent of the economic recovery will impact future earnings.

Southern Company system generating capacity increased 325 megawatts due to Southern Power’s acquisition of West Georgia Generating Company, LLC and divestiture of DeSoto County Generating Company, LLC in December 2009. 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. See FUTURE EARNINGS POTENTIAL — “Construction Program” herein and Note 7 to the financial statements for additional information.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, 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, risks, and financial condition of Southern Company.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.

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. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

Southern Company believes that the traditional 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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to

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Southern Company and Subsidiary Companies 2009 Annual Report

assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but the traditional operating companies and Southern Power were named as defendants in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

The electric utilities’ 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; the Endangered Species Act; and related federal and state regulations. 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 2009, the electric utilities had invested approximately $7.5 billion in capital projects to comply with these requirements, with annual totals of $1.3 billion, $1.6 billion, and $1.5 billion for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $545 million, $721 million, and $1.2 billion for 2010, 2011, and 2012, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect Southern Company. Although new or revised environmental legislation or regulations could affect many areas of Southern Company’s operations, 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 2009, the electric utilities have spent approximately $6.6 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality standard. A 20-county area within metropolitan Atlanta is the only location within Southern Company’s service area that is currently designated as nonattainment for the standard, which could require additional reductions in NO_x emissions from power plants. In March 2008, however, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to finalize the revised standard in August 2010 and require state implementation plans for any nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within Southern Company’s service territory.

During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia. State plans for addressing the nonattainment designations for this standard could require further reductions in SO₂ and NO_x emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. The Birmingham, Alabama area has been designated as nonattainment for the 24-hour standard, and a state implementation plan for this nonattainment area is due in December 2012.

On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard for SO₂. The EPA is expected to finalize the revised SO₂ standard in June 2010.

Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. States in the Southern Company service territory have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation of emissions controls at coal-fired facilities of the electric utilities and/or by the purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in July 2010.

The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring 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) to certain sources built between 1962 and 1977, and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural conditions goal by 2018 and for each ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and NO_x, and no additional controls beyond CAIR are anticipated to be necessary at any of the traditional operating companies’ facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress.

The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants, including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and trade program for the reduction of mercury emissions from coal-fired power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.

In February 2004, the EPA finalized the Industrial Boiler (IB) MACT rule, which imposed limits on hazardous air pollutants from industrial boilers, including biomass boilers. Compliance with the final rule was scheduled to begin in September 2007; however, in response to challenges to the final rule, the U.S. Court of Appeals for the District of Columbia Circuit vacated the IB MACT rule in its entirety in July 2007 and ordered the EPA to develop a new IB MACT rule. In September 2009, the deadline to promulgate a proposed rule was extended from July 15, 2009 to April 15, 2010, with a final rule required by December 16, 2010. The EPA is currently developing the new rule and may change the methodology to determine the MACT limits for industrial boilers.

The impacts of the eight-hour ozone standards, the fine particulate matter nonattainment designations, and future revisions to CAIR, the SO₂standard, the Clean Air Visibility Rule, and the MACT rules for electric generating units and industrial boilers on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO₂and NO_x emissions controls and plans to install additional controls within the next several years to ensure continued compliance with applicable air quality requirements. In addition, most units in Georgia are required to install specific emissions controls according to a schedule set forth in the state’s Multipollutant Rule, which is designed to reduce emissions of SO₂, NO_x, and mercury in Georgia.

Water Quality

In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is now in the process of revising the regulations. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on further rulemaking by the EPA and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

On December 28, 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions by 2013. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Southern Company system facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time.

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Southern Company and Subsidiary Companies 2009 Annual Report

Environmental Remediation

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 traditional operating companies could incur substantial costs to clean up properties. The traditional 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 traditional 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.

Coal Combustion Byproducts

The EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA has collected information from the electric utility industry on surface impoundment safety and conducted on-site inspections at three facilities of Alabama Power and Georgia Power as part of its evaluation. The traditional operating companies have a routine and robust inspection program in place to ensure the integrity of their respective coal ash surface impoundments. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010. The impact of these additional regulations on the Company will depend on the specific provisions of the final rule and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the traditional operating companies’ management, beneficial use, and disposal of such byproducts and could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

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Southern Company and Subsidiary Companies 2009 Annual Report

Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the electric utilities were approximately 142 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 121 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. These include new nuclear generation, including two additional generating units at Plant Vogtle in Georgia; proposed construction of an advanced IGCC unit with approximately 65% carbon capture in Kemper County, Mississippi; and renewables investments, including the construction of a biomass plant in Sacul, Texas. The Company is currently considering additional projects and is pursuing research into the costs and viability of other renewable technologies for the Southeast.

PSC Matters

Alabama Power

Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Retail rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13% and 14.5%. 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 ROE fall below the allowed equity return range.

On December 1, 2009, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2010. The Rate RSE increase for 2010 is 3.2%, or $152 million annually, and was effective in January 2010. The revenue adjustment under the Rate RSE is largely attributable to the costs associated with fossil capacity which is currently dedicated to certain long-term wholesale contracts that expire during 2010. Retail cost of service for 2010 reflects the cost for that portion of the year in which this capacity is no longer committed to wholesale. The termination of these long-term wholesale contracts will result in a significant decrease in unit power sales capacity revenues. In an Alabama PSC order dated January 5, 2010, the Alabama PSC acknowledged that a full calendar year of costs for such capacity would be reflected in the Rate RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the maximum increase for 2011 cannot exceed 4.76%.

The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the cost of placing new generating facilities in retail service and for the recovery of retail costs associated with certificated PPAs under a Rate Certificated New Plant (Rate CNP). There was no adjustment to Rate CNP in April 2007, 2008, or 2009. Effective April 2010, Rate CNP will be reduced approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. Rate CNP also allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital.

On December 1, 2009, Alabama Power made its Rate CNP environmental submission to the Alabama PSC of projected data for calendar year 2010. The Rate CNP environmental increase for 2010 is 4.3%, or $195 million annually, based upon projected billings. Under the terms of the rate mechanism, the adjustment became effective in January 2010. The Rate CNP environmental adjustment is primarily attributable to scrubbers being placed in service during 2010 at four of Alabama Power’s generating plants. See Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Retail Rate Plans” for further information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Georgia Power

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail ROE range of 10.25% to 12.25%. Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs related to environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008.

In connection with the 2007 Retail Rate Plan, Georgia Power agreed that it would not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, Georgia Power’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations.

On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail ROE. For the year ended December 31, 2009, Georgia Power amortized $41 million of the regulatory liability. In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. Georgia Power is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” for additional information.

Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In previous years, the traditional operating companies experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $667 million at December 31, 2009. During the third quarter 2009, Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of December 31, 2009, have a total over recovered fuel balance of $229 million. The total under recovered fuel costs included in the balance sheets of the traditional operating companies at December 31, 2008 was $1.2 billion. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.

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, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Fuel Cost Recovery” and “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” for additional information.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Southern Company. Southern Company’s cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA was approximately $250 million. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of Southern Company.

On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted under the ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Southern Company continues to assess the other financial implications of the ARRA.

The U.S. House of Representatives and the U.S. Senate have passed separate bills related to healthcare reform. Both bills include a provision that would make Medicare Part D subsidy reimbursements taxable. If enacted into law, this provision could have a

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

significant negative impact on Southern Company’s net income. See Note 2 to the financial statements under “Other Postretirement Benefits” for additional information.

The ultimate impact of these matters cannot be determined at this time.

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. The ultimate outcome of this matter cannot now be determined.

Internal Revenue Code Section 199 Domestic Production Deduction

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Construction Program

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including units at Southern Power, proposed new nuclear units, and a proposed IGCC facility, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements under “Construction Program” for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” for additional information.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

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 traditional operating companies, which comprised approximately 97% of Southern Company’s total operating revenues for 2009, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional operating companies are permitted to charge customers based on allowable costs. As a result, the traditional operating companies apply accounting standards which require 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 the accounting standards 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 traditional 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, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters.

• Changes in existing income tax regulations or changes in IRS or state revenue department 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 new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Unbilled Revenues

Revenues related to the retail 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.

Pension and Other Postretirement Benefits

Southern Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining Southern Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on Southern Company’s investment strategy, historical experience, and expectations for long-term rates of return that considers external actuarial advice.

Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company’s target asset allocation. Southern Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

The following table illustrates the sensitivity to changes in Southern Company’s long-term assumptions with respect to the expected long-term rate of return on plan assets and the assumed discount rate:

			Increase/(Decrease) in
		Increase/(Decrease) in	Projected Obligation for
	Increase/(Decrease) in	Projected Obligation for	Other Postretirement
	Total Benefit Expense	Pension Plan	Benefit Plans
Change in Assumption	for 2010	at December 31, 2009	at December 31, 2009
	(in millions)
25 basis point change in discount rate	$11/$(8)	$226/$(214)	$53/$(51)
25 basis point change in salary assumption	$9/$(8)	$58/$(55)	N/M
25 basis point change in long-term return on plan assets	$19/$(19)	N/M	N/M

N/M – Not meaningful

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Southern Company adopted this new guidance effective January 1, 2010, with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at December 31, 2009. Throughout the turmoil in the financial markets, Southern Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Southern Company and its subsidiaries have been and expect to continue to be subject to higher costs as existing facilities are replaced or renewed. Total committed credit fees for Southern Company and its subsidiaries currently average less than¹/2 of 1% per year. See “Sources of Capital” and “Financing Activities” herein for additional information.

Southern Company’s investments in pension and nuclear decommissioning trust funds remained stable in value as of December 31, 2009. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

Net cash provided from operating activities in 2009 totaled $3.3 billion, a decrease of $201 million from the corresponding period in 2008. Significant changes in operating cash flow for 2009 as compared to the corresponding period in 2008 include a reduction to net income as previously discussed, increased levels of coal inventory, and increased cash outflows for tax payments. These uses of funds were partially offset by increased cash inflows as a result of higher fuel cost recovery rates included in customer billings. Net cash provided from operating activities in 2008 totaled $3.5 billion, an increase of $30 million as compared to 2007. Significant changes in operating cash flow for 2008 included a $264 million increase in the use of funds for fossil fuel inventory as compared to the corresponding period in 2007. This use of funds was offset by an increase in cash of $312 million in accrued taxes primarily due to a difference between the periods in payments for federal taxes and property taxes. Net cash provided from operating activities in 2007 totaled $3.4 billion, an increase of $583 million as compared to the corresponding period in 2006. The increase was primarily due to an increase in net income as previously discussed, an increase in cash collections from previously deferred fuel and storm damage costs, and a reduction in cash outflows compared to the previous year in fossil fuel inventory.

Net cash used for investing activities in 2009 totaled $4.3 billion primarily due to property additions to utility plant of $4.7 billion, partially offset by approximately $340 million in cash received from the early termination of two leveraged lease investments. Net cash used for investing activities in 2008 totaled $4.1 billion primarily due to property additions to utility plant of $4.0 billion. In 2007, net cash used for investing activities was $3.7 billion primarily due to property additions to utility plant of $3.5 billion.

Net cash provided from financing activities totaled $1.3 billion in 2009 primarily due to the issuance of new long-term debt and common stock issuances, partially offset by cash outflows for repayments of long-term debt and dividend payments. Net cash provided from financing activities totaled $878 million in 2008 primarily due to long-term debt issuances. Net cash provided from financing activities totaled $309 million in 2007 primarily due to replacement of short-term debt with longer term financing and cash raised from common stock programs.

Significant balance sheet changes in 2009 include an increase of $3.4 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

significant changes include an increase in long-term debt, excluding amounts due within one year, of $1.3 billion used primarily for construction expenditures and general corporate purposes and $1.6 billion of additional equity.

At the end of 2009, the closing price of Southern Company’s common stock was $33.32 per share, compared with book value of $18.15 per share. The market-to-book value ratio was 184% at the end of 2009, compared with 217% at year-end 2008.

Southern Company, each of the traditional operating companies, and Southern Power have received investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. Southern Company Services, Inc. has an investment grade corporate credit rating. See “Credit Rating Risk” herein for additional information.

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 2010, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.

The traditional operating companies and Southern Power 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, term loans, short-term borrowings, and equity contributions from Southern Company. However, the type and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In addition, on February 16, 2010, the U.S. Department of Energy (DOE) offered Georgia Power a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Georgia Power has 90 days to accept the conditional commitment, including obtaining any necessary regulatory approvals. Georgia Power will work with the DOE to finalize loan guarantees. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the Nuclear Regulatory Commission (NRC), negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. The issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. 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 (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts, if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Southern Company, each traditional operating company, and Southern Power obtain 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 substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities).

At December 31, 2009, Southern Company and its subsidiaries had approximately $690 million of cash and cash equivalents and $4.8 billion of unused credit arrangements with banks, of which $1.5 billion expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $81 million of the credit facilities expiring in 2010 allow for the execution of term loans for an additional two-year period, and $517 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. A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2009 was approximately $1.6 billion. Subsequent to December 31, 2009, two remarketings of pollution control revenue bonds increased that amount to $1.8 billion. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

Financing Activities

During 2009, Southern Company issued $350 million of Series 2009A 4.15% Senior Notes due May 15, 2014 and $300 million of Series 2009B Floating Rate Senior Notes due October 21, 2011, and its subsidiaries issued $1.8 billion of senior notes and incurred obligations of $625 million related to the issuance of pollution control revenue bonds. A portion of the proceeds of the newly issued pollution control revenue bonds were used to retire $327 million of outstanding pollution control revenue bonds. Southern Company also issued 22.6 million shares of common stock for $673 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 19.9 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $613 million, net of $6 million in fees and commissions. The proceeds were primarily used to redeem or repay at maturity $1.2 billion of long-term debt, to fund ongoing construction projects, to repay short-term and long-term indebtedness, and for general corporate purposes.

Also during 2009, Georgia Power and Gulf Power entered into forward starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amounts of the swaps totaled $200 million and $100 million, respectively. Georgia Power had net realized losses of $19 million upon termination of $300 million of interest rate hedges during 2009. The effective portion of these losses has been deferred in other comprehensive income and is being amortized to interest expense over the life of the original interest rate hedge.

In 2009, Southern Company used a portion of the cash received from the early termination of two leveraged lease investments to extinguish $253 million of debt which included all debt related to these leveraged lease investments and to pay make-whole redemption premiums of $17 million associated with such debt.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan 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 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% 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% 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. In April 2010, 18 months prior to the end of the initial lease term, Mississippi Power may elect to renew for 10 years. 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 of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation facilities. At December 31, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $467 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.3 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

On September 2, 2009, Moody’s Investors Service (Moody’s) affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A3/P-1, respectively, and revised the rating outlook for Southern Company to negative. On September 4, 2009, Fitch Ratings, Inc. affirmed Southern Company’s long-term and commercial paper credit ratings of A/F1, respectively, and maintained its stable rating outlook. On October 6, 2009, Standard and Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc. (S&P) affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A-/A-1, respectively, and maintained a stable rating outlook.

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, where possible, 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 a change in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. Derivatives outstanding at December 31, 2009 have a notional amount of $976 million and are related to anticipated debt issuances and various floating rate obligations over the next year. The weighted average interest rate on $2.7 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2010 was 0.76%. 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 $27 million at January 1, 2010. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

Due to cost-based rate regulation, the traditional operating companies continue to 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. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs.

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

	2009			2008
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(285	)	$	4
Contracts realized or settled		367			(150	)
Current period changes(a)		(260	)		(139	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(178	)	$	(285	)

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

The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2009 was an increase of $107 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and prices of natural gas. At December 31, 2009, Southern Company had a net hedge volume of 154 million mmBtu (includes location basis of 2 million mmBtu) with a weighted average contract cost approximately $1.17 per mmBtu above market prices, compared to 149 million mmBtu (includes location basis of 2 million mmBtu) at December 31, 2008 with a weighted average contract cost approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedges are recorded through the traditional operating companies’ fuel cost recovery clauses.

II-35

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows:

Asset (Liability) Derivatives	2009			2008
	(in millions)
Regulatory hedges	$	(175	)	$	(288	)
Cash flow hedges		(2	)		(1	)
Not designated		(1	)		4
Total fair value	$	(178	)	$	(285	)

Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2009, 2008, and 2007 for energy-related derivative contracts that are not hedges were $(5) million, $1 million, and $3 million, respectively.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(178	)		(113	)		(65	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(178	)	$	(113	)	$	(65	)	$	—

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion on fair value measurement.

Southern Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P 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 Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company’s domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company’s international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.

During 2007, Southern Company had derivatives in place to reduce its exposure to a phase-out of certain income tax credits related to synthetic fuel production in 2007. In accordance with Internal Revenue Code Section 45K, these tax credits were subject to limitation as the annual average price of oil increased. Because these transactions were not designated as hedges, the gains and losses were recognized in the statements of income as incurred. These derivatives settled on January 1, 2008 and thus there was no income statement impact for the years ended December 31, 2008 and 2009. For 2007, the unrealized fair value gain recognized in other income to mark the transactions to market was $27 million.

II-36

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Capital Requirements and Contractual Obligations

The construction program of Southern Company is currently estimated to be $4.9 billion for 2010, $5.3 billion for 2011, and $6.2 billion for 2012. These estimates include costs for new generation construction. Environmental expenditures included in these estimated amounts are $545 million, $721 million, and $1.2 billion for 2010, 2011, and 2012, respectively. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” and Note 7 to the financial statements under “Construction Program” for additional information.

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.”

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 traditional operating companies’ respective regulatory commissions.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, 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, 7, and 11 to the financial statements for additional information.

II-37

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(d)		Total
	(in millions)
Long-term debt(a) —
Principal	$	1,092	$	2,880	$	1,361	$	13,836	$	—	$	19,169
Interest		894		1,732		1,455		11,905		—		15,986
Preferred and preference stock dividends(b)		65		130		130		—		—		325
Other derivative obligations(c) —
Energy-related		119		66		—		—		—		185
Operating leases		144		192		99		124		—		559
Capital leases		21		26		11		40		—		98
Unrecognized tax benefits and interest(d)		184		—		—		—		36		220
Purchase commitments(e) —
Capital(f)		4,665		11,160		—		—		—		15,825
Limestone(g)		37		72		76		110		—		295
Coal		4,490		4,707		1,913		2,508		—		13,618
Nuclear fuel		271		323		231		297		—		1,122
Natural gas(h)		1,349		2,192		1,504		4,153		—		9,198
Biomass fuel(i)		—		17		35		128		—		180
Purchased power		253		524		502		2,742		—		4,021
Long-term service agreements(j)		103		251		263		1,738		—		2,355
Trusts —
Nuclear decommissioning(k)		3		7		7		53		—		70
Postretirement benefits(l)		43		76		—		—		—		119
Total	$	13,733	$	24,355	$	7,587	$	37,634	$	36	$	83,345

(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, 2010, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Excludes capital lease amounts (shown separately).
(b)	Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(c)	For additional information, see Notes 1 and 11 to the financial statements.
(d)	The timing related to the realization of $36 million in unrecognized tax benefits and interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Notes 3 and 5 to the financial statements for additional information.
(e)	Southern Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2009, 2008, and 2007 were $3.5 billion, $3.8 billion, and $3.7 billion, respectively.
(f)	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 nuclear fuel. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program.
(g)	As part of Southern Company’s program to reduce sulfur dioxide emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment.
(h)	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, 2009.
(i)	Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases.
(j)	Long-term service agreements include price escalation based on inflation indices.
(k)	Projections of nuclear decommissioning trust contributions are based on the 2007 Retail Rate Plan and are subject to change in Georgia Power’s 2010 retail rate case.
(l)	Southern Company forecasts postretirement trust contributions over a three-year period. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Therefore, no amounts related to the pension trust fund are included in the table. 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.

II-38

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, earnings, dividend payout ratios, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project, impact of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances, and also changes in 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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trusts;

• advances in technology;

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

• regulatory approvals and actions related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

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

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

II-39

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2007
				(in millions)
Operating Revenues:
Retail revenues	$	13,307		$	14,055		$	12,639
Wholesale revenues		1,802			2,400			1,988
Other electric revenues		533			545			513
Other revenues		101			127			213
Total operating revenues		15,743			17,127			15,353
Operating Expenses:
Fuel		5,952			6,818			5,856
Purchased power		474			815			515
Other operations and maintenance		3,526			3,748			3,670
MC Asset Recovery litigation settlement		202			—			—
Depreciation and amortization		1,503			1,443			1,245
Taxes other than income taxes		818			797			741
Total operating expenses		12,475			13,621			12,027
Operating Income		3,268			3,506			3,326
Other Income and (Expense):
Allowance for equity funds used during construction		200			152			106
Interest income		23			33			45
Equity in (losses) income of unconsolidated subsidiaries		(1	)		11			(24	)
Leveraged lease income (losses)		31			(85	)		40
Gain on disposition of lease termination		26			—			—
Loss on extinguishment of debt		(17	)		—			—
Interest expense, net of amounts capitalized		(905	)		(866	)		(886	)
Other income (expense), net		(21	)		(29	)		10
Total other income and (expense)		(664	)		(784	)		(709	)
Earnings Before Income Taxes		2,604			2,722			2,617
Income taxes		896			915			835
Consolidated Net Income		1,708			1,807			1,782
Dividends on Preferred and Preference Stock of Subsidiaries		65			65			48
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	1,643		$	1,742		$	1,734
Common Stock Data:
Earnings per share (EPS)—
Basic EPS	$	2.07		$	2.26		$	2.29
Diluted EPS		2.06			2.25			2.28
Average number of shares of common stock outstanding — (in millions)
Basic		795			771			756
Diluted		796			775			761
Cash dividends paid per share of common stock	$	1.7325		$	1.6625		$	1.595

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

II-40

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2007
				(in millions)
Operating Activities:
Consolidated net income	$	1,708		$	1,807		$	1,782
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		1,788			1,704			1,486
Deferred income taxes		25			215			7
Deferred revenues		(54	)		120			(2	)
Allowance for equity funds used during construction		(200	)		(152	)		(106	)
Equity in (income) losses of unconsolidated subsidiaries		1			(11	)		24
Leveraged lease (income) losses		(31	)		85			(40	)
Gain on disposition of lease termination		(26	)		—			—
Loss on extinguishment of debt		17			—			—
Pension, postretirement, and other employee benefits		(3	)		21			39
Stock based compensation expense		23			20			28
Hedge settlements		(19	)		15			10
Other, net		79			(97	)		80
Changes in certain current assets and liabilities —
-Receivables		585			(176	)		165
-Fossil fuel stock		(432	)		(303	)		(39	)
-Materials and supplies		(39	)		(23	)		(71	)
-Other current assets		(47	)		(36	)		—
-Accounts payable		(125	)		(74	)		105
-Accrued taxes		(95	)		293			(19	)
-Accrued compensation		(226	)		36			(40	)
-Other current liabilities		334			20			25
Net cash provided from operating activities		3,263			3,464			3,434
Investing Activities:
Property additions		(4,670	)		(3,961	)		(3,546	)
Investment in restricted cash from pollution control revenue bonds		(55	)		(96	)		(157	)
Distribution of restricted cash from pollution control revenue bonds		119			69			78
Nuclear decommissioning trust fund purchases		(1,234	)		(720	)		(783	)
Nuclear decommissioning trust fund sales		1,228			712			775
Proceeds from property sales		340			34			33
Cost of removal, net of salvage		(119	)		(123	)		(108	)
Change in construction payables		215			83			38
Other investing activities		(143	)		(124	)		(39	)
Net cash used for investing activities		(4,319	)		(4,126	)		(3,709	)
Financing Activities:
Decrease in notes payable, net		(306	)		(314	)		(669	)
Proceeds —
Long-term debt issuances		3,042			3,687			3,826
Preferred and preference stock		—			—			470
Common stock issuances		1,286			474			538
Redemptions —
Long-term debt		(1,234	)		(1,469	)		(2,565	)
Redeemable preferred stock		—			(125	)		—
Payment of common stock dividends		(1,369	)		(1,280	)		(1,205	)
Payment of dividends on preferred and preference stock of subsidiaries		(65	)		(66	)		(40	)
Other financing activities		(25	)		(29	)		(46	)
Net cash provided from financing activities		1,329			878			309
Net Change in Cash and Cash Equivalents		273			216			34
Cash and Cash Equivalents at Beginning of Year		417			201			167
Cash and Cash Equivalents at End of Year	$	690		$	417		$	201

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

II-41

CONSOLIDATED BALANCE SHEETS

At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report

Assets	2009			2008
	(in millions)
Current Assets:
Cash and cash equivalents	$	690		$	417
Restricted cash and cash equivalents		43			103
Receivables —
Customer accounts receivable		953			1,054
Unbilled revenues		394			320
Under recovered regulatory clause revenues		333			646
Other accounts and notes receivable		375			301
Accumulated provision for uncollectible accounts		(25	)		(26	)
Fossil fuel stock, at average cost		1,447			1,018
Materials and supplies, at average cost		794			757
Vacation pay		145			140
Prepaid expenses		508			302
Other regulatory assets, current		167			275
Other current assets		49			51
Total current assets		5,873			5,358
Property, Plant, and Equipment:
In service		53,588			50,618
Less accumulated depreciation		19,121			18,286
Plant in service, net of depreciation		34,467			32,332
Nuclear fuel, at amortized cost		593			510
Construction work in progress		4,170			3,036
Total property, plant, and equipment		39,230			35,878
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,070			864
Leveraged leases		610			897
Miscellaneous property and investments		283			227
Total other property and investments		1,963			1,988
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,047			973
Unamortized debt issuance expense		208			208
Unamortized loss on reacquired debt		255			271
Deferred under recovered regulatory clause revenues		373			606
Other regulatory assets, deferred		2,702			2,636
Other deferred charges and assets		395			429
Total deferred charges and other assets		4,980			5,123
Total Assets	$	52,046		$	48,347

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

II-42

CONSOLIDATED BALANCE SHEETS
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report

Liabilities and Stockholders’ Equity	2009		2008
	(in millions)
Current Liabilities:
Securities due within one year	$	1,113	$	617
Notes payable		639		953
Accounts payable		1,329		1,250
Customer deposits		331		302
Accrued taxes —
Accrued income taxes		13		197
Unrecognized tax benefits		166		131
Other accrued taxes		398		396
Accrued interest		218		196
Accrued vacation pay		184		179
Accrued compensation		248		447
Liabilities from risk management activities		125		261
Other regulatory liabilities, current		528		78
Other current liabilities		292		219
Total current liabilities		5,584		5,226
Long-Term Debt(See accompanying statements)		18,131		16,816
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,455		6,080
Deferred credits related to income taxes		248		259
Accumulated deferred investment tax credits		448		455
Employee benefit obligations		2,304		2,057
Asset retirement obligations		1,201		1,183
Other cost of removal obligations		1,091		1,321
Other regulatory liabilities, deferred		278		262
Other deferred credits and liabilities		346		330
Total deferred credits and other liabilities		12,371		11,947
Total Liabilities		36,086		33,989
Redeemable Preferred Stock of Subsidiaries(See accompanying statements)		375		375
Total Stockholders’ Equity(See accompanying statements)		15,585		13,983
Total Liabilities and Stockholders’ Equity	$	52,046	$	48,347
Commitments and Contingent Matters(See notes)

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

II-43

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report

		2009			2008			2009			2008
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Maturity	Interest Rates
2044	5.88%	$	206		$	206
Variable rate (3.35% at 1/1/10) due 2042			206			206
Total long-term debt payable to affiliated trusts			412			412
Long-term senior notes and debt —
Maturity	Interest Rates
2009	4.10% to 7.00%		—			128
2010	4.70%		102			102
2011	4.00% to 5.57%		304			303
2012	4.85% to 6.25%		1,778			1,778
2013	4.35% to 6.00%		936			936
2014	4.15% to 4.90%		425			75
2015 through 2048	4.25% to 8.20%		9,847			8,362
Adjustable rates (at 1/1/10):
2009	2.3288% to 2.36%		—			440
2010	0.35% to 0.97%		990			1,034
2011	0.68% to 2.95%		790			490
Total long-term senior notes and debt			15,172			13,648
Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
2016 through 2048	1.40% to 6.00%		1,973			2,030
Variable rates (at 1/1/10):
2011 through 2049	0.18% to 0.44%		1,612			1,257
Total other long-term debt			3,585			3,287
Capitalized lease obligations			98			106
Unamortized debt (discount), net			(23	)		(20	)
Total long-term debt (annual interest requirement — $894 million)			19,244			17,433
Less amount due within one year			1,113			617
Long-term debt excluding amount due within one year			18,131			16,816			53.2	%		53.9	%

II-44

CONSOLIDATED STATEMENTS OF CAPITALIZATION(continued)
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2009			2008
	(in millions)						(percent of total)
Redeemable Preferred Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 5.44%
Authorized — 20 million shares
Outstanding — 1 million shares		81			81
$1 par value — 4.95% to 5.83%
Authorized — 28 million shares
Outstanding — 12 million shares: $25 stated value		294			294
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $20 million)		375			375			1.1			1.2
Common Stockholders’ Equity:
Common stock, par value $5 per share —		4,101			3,888
Authorized — 1 billion shares
Issued — 2009: 820 million shares
— 2008: 778 million shares
Treasury — 2009: 0.5 million shares
— 2008: 0.4 million shares
Paid-in capital		2,995			1,893
Treasury, at cost		(15	)		(12	)
Retained earnings		7,885			7,612
Accumulated other comprehensive income (loss)		(88	)		(105	)
Total common stockholders’ equity		14,878			13,276			43.6			42.6
Preferred and Preference Stock of Subsidiaries:
Non-cumulative preferred stock
$25 par value — 6.00% to 6.13%
Authorized — 60 million shares
Outstanding — 2 million shares		45			45
Preference stock
Authorized — 65 million shares
Outstanding — $1 par value — 5.63% to 6.50%		343			343
— 14 million shares (non-cumulative)
— $100 par or stated value — 6.00% to 6.50%		319			319
— 3 million shares (non-cumulative)
Total preferred and preference stock of subsidiaries (annual dividend requirement — $45 million)		707			707			2.1			2.3
Total stockholders’ equity		15,585			13,983
Total Capitalization	$	34,091		$	31,174			100.0	%		100.0	%

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

II-45

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report

																Accumulated			Preferred
																Other			and
	Number of					Common Stock										Comprehensive			Preference
	Common Shares					Par		Paid-In					Retained			Income			Stock of
	Issued		Treasury			Value		Capital		Treasury			Earnings			(Loss)			Subsidiaries		Total
	(in thousands)					(in millions)
Balance at December 31, 2006		751,864		(5,594	)	$	3,759	$	1,096	$	(192	)	$	6,765		$	(57	)	$	246	$	11,617
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			1,734			—			—		1,734
Other comprehensive income		—		—			—		—		—			—			27			—		27
Cumulative effect of new accounting standards (a)		—		—			—		—		—			(140	)		—			—		(140	)
Stock issued		11,639		5,255			58		356		183			—			—			461		1,058
Cash dividends		—		—			—		—		—			(1,204	)		—			—		(1,204	)
Other		—		(60	)		—		2		(2	)		—			—			—		—
Balance at December 31, 2007		763,503		(399	)		3,817		1,454		(11	)		7,155			(30	)		707		13,092
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			1,742			—			—		1,742
Other comprehensive income		—		—			—		—		—			—			(75	)		—		(75	)
Stock issued		14,113		—			71		438		—			—			—			—		509
Cash dividends		—		—			—		—		—			(1,279	)		—			—		(1,279	)
Other		—		(25	)		—		1		(1	)		(6	)		—			—		(6	)
Balance at December 31, 2008		777,616		(424	)		3,888		1,893		(12	)		7,612			(105	)		707		13,983
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			1,643			—			—		1,643
Other comprehensive income		—		—			—		—		—			—			17			—		17
Stock issued		42,536		—			213		1,100		—			—			—			—		1,313
Cash dividends		—		—			—		—		—			(1,369	)		—			—		(1,369	)
Other		—		(81	)		—		2		(3	)		(1	)		—			—		(2	)
Balance at December 31, 2009		820,152		(505	)	$	4,101	$	2,995	$	(15	)	$	7,885		$	(88	)	$	707	$	15,585

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

(a) In 2007 Southern Company recorded two adjustments net of tax in respect of new accounting guidance; a $125 million adjustment in respect of leverage lease transactions and a $15 million adjustment in respect of uncertain tax positions.

II-46

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2007
	(in millions)
Consolidated Net Income	$	1,708		$	1,807		$	1,782
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $(3), $(19), and $(3), respectively		(4	)		(30	)		(5	)
Reclassification adjustment for amounts included in net income, net of tax of $18, $7, and $6, respectively		28			11			9
Marketable securities:
Change in fair value, net of tax of $1, $(4), and $3, respectively		4			(7	)		4
Reclassification adjustment for amounts included in net income, net of tax of$-, $-, and $-, respectively		—			—			(1	)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss),net of tax of $(8), $(32), and $13, respectively		(12	)		(51	)		20
Additional prior service costs from amendment to non-qualified plans, net of tax of$-, $-, and $(2), respectively		—			—			(2	)
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively		1			2			2
Total other comprehensive income (loss)		17			(75	)		27
Dividends on preferred and preference stock of subsidiaries		(65	)		(65	)		(48	)
Consolidated Comprehensive Income	$	1,660		$	1,667		$	1,761

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

II-47

NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2009 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

The Southern Company (the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power), are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

The financial statements reflect Southern Company’s investments in the subsidiaries on a consolidated basis. The equity method is used for entities 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 transactions have been eliminated in consolidation. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC) and the traditional 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 purchased synthetic fuel from Alabama Fuel Products, LLC (AFP), an entity in which Southern Holdings held a 30% ownership interest until July 2006, when its ownership interest was terminated. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings, provided fuel transportation services to AFP that were ultimately reflected in the cost of the synthetic fuel billed to Alabama Power and Georgia Power. Subsequent to the termination of Southern Company’s membership interest in AFP, Alabama Power and Georgia Power continued to purchase an additional $6 million and $750 million in fuel from AFP in 2008 and 2007, respectively. SSI continued to provide fuel transportation services of $131 million in 2007, which were eliminated against fuel expense in the financial statements. SSI also provided other additional services to AFP and a related party of AFP totaling $47 million in 2007. The synthetic fuel investments and related party transactions were terminated on December 31, 2007.

II-48

NOTES (continued)

Southern Company and Subsidiary Companies 2009 Annual Report

Regulatory Assets and Liabilities

The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate 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:

	2009			2008			Note
	(in millions)
Deferred income tax charges	$	1,048		$	972			(a	)
Asset retirement obligations-asset		125			236			(a,i	)
Asset retirement obligations-liability		(47	)		(5	)		(a,i	)
Other cost of removal obligations		(1,307	)		(1,321	)		(a	)
Deferred income tax credits		(249	)		(260	)		(a	)
Loss on reacquired debt		255			271			(b	)
Vacation pay		145			140			(c,i	)
Under recovered regulatory clause revenues		40			432			(d	)
Over recovered regulatory clause revenues		(218	)		(3	)		(d	)
Building leases		47			49			(f	)
Generating plant outage costs		39			45			(d	)
Under recovered storm damage costs		22			27			(d	)
Property damage reserves		(157	)		(97	)		(h	)
Fuel hedging-asset		187			314			(d	)
Fuel hedging-liability		(2	)		(10	)		(d	)
Other assets		156			163			(d	)
Environmental remediation-asset		68			67			(h,i	)
Environmental remediation-liability		(13	)		(19	)		(h	)
Environmental compliance cost recovery		(96	)		(135	)		(g	)
Other liabilities		(51	)		(43	)		(j	)
Underfunded retiree benefit plans		2,268			2,068			(e,i	)
Total assets (liabilities), net	$	2,260		$	2,891

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, other cost of removal, and deferred tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. Other cost of removal obligations include $216 million at Georgia Power that may be amortized during 2010 in accordance with the August 27, 2009 Georgia PSC order. See Note 3 under “Retail Regulatory Matters — Georgia Power — Cost of Removal” for additional information.
(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 over periods not exceeding 10 years.
(e)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
(f)	Recovered over the remaining lives of the buildings through 2026.
(g)	This balance represents deferred revenue associated with Georgia Power’s environmental compliance cost recovery (ECCR) tariff established in its retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan). The recovery of the forecasted environmental compliance costs was levelized to collect equal annual amounts between January 1, 2008 and December 31, 2010 under the tariff.
(h)	Recovered as storm restoration or environmental remediation expenses are incurred.
(i)	Not earning a return as offset in rate base by a corresponding asset or liability.
(j)	Recorded and recovered or amortized as approved by the appropriate state PSC over periods up to the life of the plant or the remaining life of the original issue or, if refinanced, over the life of the new issue which may range up to 50 years.

In the event that a portion of a traditional operating company’s operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off or reclassify to accumulated other comprehensive income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional 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 values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory Matters — Alabama Power,” “Retail Regulatory Matters — Georgia Power,” and “Retail Regulatory Matters — Integrated Coal Gasification Combined Cycle” for additional information.

II-49

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Revenues

Wholesale 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 related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional 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 cost recovery mechanisms vary by each traditional 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. Georgia Power filed a new fuel case on December 15, 2009. The new rates are expected to become effective April 1, 2010. Gulf Power is required to notify the Florida PSC if the projected fuel cost over or under recovery exceeds 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually. See Note 3 under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” for additional information.

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

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emissions 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. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information.

Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with regulatory requirements, deferred investment tax credits (ITCs) for the traditional operating companies 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 $24 million in 2009, $23 million in 2008, and $23 million in 2007. At December 31, 2009, all ITCs available to reduce federal income taxes payable had been utilized.

Under the American Recovery and Reinvestment Act of 2009, certain renewable projects at Southern Company’s non-regulated subsidiaries are eligible for ITCs or cash grants. These non-regulated companies have elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized over the life of the asset, and the tax basis of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The non-regulated companies have elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. This basis difference will reverse and be recorded to income tax expense over the useful life of the asset once placed in service.

In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

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.

II-50

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

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

	2009		2008
	(in millions)
Generation	$	28,204	$	26,154
Transmission		7,380		7,085
Distribution		14,335		13,856
General		2,917		2,750
Plant acquisition adjustment		43		43
Utility plant in service		52,879		49,888
IT equipment and software		182		240
Communications equipment		423		450
Other		104		40
Other plant in service		709		730
Total plant in service	$	53,588	$	50,618

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 nuclear refueling costs in advance of the unit’s next refueling outage. Georgia Power defers and amortizes nuclear 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.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2% in 2009, 3.2% in 2008, and 3.0% in 2007. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $18.7 billion and $17.9 billion at December 31, 2009 and 2008, 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 Georgia Power’s retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan), Georgia Power was ordered to recognize Georgia PSC-certified capacity costs in rates evenly over the three years covered by the 2004 Retail Rate Plan. Georgia Power recorded credits to amortization of $19 million in 2007. The 2007 Retail Rate Plan did not include a similar order. On August 27, 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. See Note 3 under “Retail Regulatory Matters — Georgia Power — Cost of Removal” for additional information.

In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify 266 megawatts (MWs) 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 amortized the related regulatory liability, pursuant to the Mississippi PSC’s order, by $6 million in 2007 resulting in an increase to earnings in that year.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 30 years. Accumulated depreciation for other plant in service totaled $419 million and $433 million at December 31, 2009 and 2008, respectively.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. The Company has received accounting guidance from the various state PSCs allowing the continued accrual of

II-51

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

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 are reflected in the balance sheets as a regulatory liability. See Note 3 under “Retail Regulatory Matters — Georgia Power — Cost of Removal” for additional information related to Georgia Power’s cost of removal regulatory liability.

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, 2009 was $1.1 billion. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the U.S. 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 in accordance with accounting standards related to asset retirement and environmental obligations, 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:

	2009			2008
	(in millions)
Balance beginning of year	$	1,185		$	1,203
Liabilities incurred		2			4
Liabilities settled		(10	)		(4	)
Accretion		77			75
Cash flow revisions		(48	)		(93	)
Balance end of year	$	1,206		$	1,185

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 (the 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 Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. In addition, the NRC prohibits investments in securities of power reactor licensees. While Southern Company is allowed to prescribe an overall investment policy to the Funds’ managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by Southern Company, Alabama Power, and Georgia Power management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the investment return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized, unrealized, or identified as other-than-temporary, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Fair value adjustments, realized gains, and other-than-temporary impairment losses are determined on a specific identification basis.

At December 31, 2009, investment securities in the Funds totaled $1.1 billion consisting of equity securities of $774 million, debt securities of $272 million, and $22 million of other securities. At December 31, 2008, investment securities in the Funds totaled $862 million consisting of equity securities of $518 million, debt securities of $323 million, and $21 million of other securities. These amounts exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases.

II-52

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Sales of the securities held in the Funds resulted in cash proceeds of $1.2 billion, $712 million, and $775 million in 2009, 2008, and 2007, respectively, all of which were reinvested. For 2009, fair value increases, including reinvested interest and dividends and excluding expenses, were $215 million, of which $198 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding expenses, were $(278) million. Realized gains and other-than-temporary impairment losses were $78 million and $(76) million, respectively, in 2007. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statement of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired.

Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. 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, 2009, the accumulated provisions for decommissioning were as follows:

	Plant Farley		Plant Hatch		Plant Vogtle
			(in millions)
External trust funds	$	490	$	360	$	206
Internal reserves		25		—		—
Total	$	515	$	360	$	206

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 2008 for Plant Farley and in 2009 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plants Hatch and Vogtle:

	Plant Farley		Plant Hatch		Plant Vogtle
Decommissioning periods:
Beginning year		2037		2034		2047
Completion year		2065		2063		2067
			(in millions)
Site study costs:
Radiated structures	$	1,060	$	583	$	500
Non-radiated structures		72		46		71
Total	$	1,132	$	629	$	571

The decommissioning periods and site study costs for Plant Vogtle reflect the extended operating license approved by the NRC on June 3, 2009. 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 2006. The estimates used in current rates are $531 million and $366 million for Plants Hatch and Vogtle, respectively. Amounts expensed were $3 million annually for 2009 and 2008 and $7 million for 2007 for Plant Vogtle. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.9% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.9% for Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts previously contributed to the external trust funds for Plants Hatch and Farley are currently projected to be adequate to meet the decommissioning obligations.

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

In accordance with regulatory treatment, the traditional operating companies record AFUDC, which 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. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies’ regulated rates is capitalized in accordance with

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Southern Company and Subsidiary Companies 2009 Annual Report

standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 15.3%, 11.2%, and 8.4% of net income for 2009, 2008, and 2007, respectively.

Cash payments for interest totaled $788 million, $787 million, and $798 million in 2009, 2008, and 2007, respectively, net of amounts capitalized of $84 million, $71 million, and $64 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 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.

Storm Damage Reserves

Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $44 million in 2009. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2009, such additional accruals totaled $40 million. There were no material accruals for 2008 or 2007.

Leveraged Leases

Southern Company has several leveraged lease agreements, with terms 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 depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.

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

	2009			2008
	(in millions)
Net rentals receivable	$	487		$	492
Unearned income		(218	)		(230	)
Investment in leveraged leases		269			262
Deferred taxes from leveraged leases		(211	)		(189	)
Net investment in leveraged leases	$	58		$	73

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

	2009			2008			2007
	(in millions)
Pretax leveraged lease income	$	12		$	14		$	16
Income tax expense		(5	)		(6	)		(7	)
Net leveraged lease income	$	7		$	8		$	9

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NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

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

	2009			2008
	(in millions)
Net rentals receivable	$	734		$	1,298
Unearned income		(393	)		(663	)
Investment in leveraged leases		341			635
Current taxes payable		—			(120	)
Deferred taxes from leveraged leases		(40	)		(117	)
Net investment in leveraged leases	$	301		$	398

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

	2009			2008			2007
	(in millions)
Pretax leveraged lease income (loss)	$	19		$	(99	)	$	24
Income tax benefit (expense)		(7	)		35			(8	)
Net leveraged lease income (loss)	$	12		$	(64	)	$	16

The Company terminated two international leveraged lease investments during 2009. The proceeds were used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions. This resulted in a $17 million loss which partially offset a $26 million gain on the terminations.

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, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

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 (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. Substantially all of Southern Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional 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, including derivatives related to synthetic fuel investments, are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

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NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2009, the amount included in “Accounts payable” in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was not material.

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.

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, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Accumulated other comprehensive income (loss) balances, net of tax effects, were as follows:

						Pension and Other			Accumulated Other
	Qualifying			Marketable		Postretirement			Comprehensive
	Hedges			Securities		Benefit Plans			Income (Loss)
						(in millions)
Balance at December 31, 2008	$	(73	)	$	6	$	(38	)	$	(105	)
Current period change		24			4		(11	)		17
Balance at December 31, 2009	$	(49	)	$	10	$	(49	)	$	(88	)

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain of the traditional operating companies have established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the applicable traditional operating companies are not considered 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 included in Long-term Debt in the balance sheets.

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). No contributions to the plan are expected for the year ending December 31, 2010. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2010, postretirement trust contributions are expected to total approximately $43 million.

The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to accounting standards related to defined postretirement benefit plans, Southern Company was required to change the measurement date for its defined postretirement benefit plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, Southern Company adopted the measurement date provisions effective January 1, 2008, resulting in an increase in long-term liabilities of $28 million and an increase in prepaid pension costs of approximately $16 million.

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Southern Company and Subsidiary Companies 2009 Annual Report

Pension Plans

The total accumulated benefit obligation for the pension plans was $6.3 billion in 2009 and $5.5 billion in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	5,879		$	5,660
Service cost		146			182
Interest cost		387			435
Benefits paid		(282	)		(324	)
Actuarial loss (gain)		628			(74	)
Balance at end of year		6,758			5,879
Change in plan assets
Fair value of plan assets at beginning of year		5,093			7,624
Actual return (loss) on plan assets		792			(2,234	)
Employer contributions		24			27
Benefits paid		(282	)		(324	)
Fair value of plan assets at end of year		5,627			5,093
Accrued liability	$	(1,131	)	$	(786	)

At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension plans were $6.3 billion and $0.4 billion, respectively. All pension plan assets are related to the qualified pension 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). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of December 31, 2009 and 2008, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		29	%		33	%		34	%
International equity		28			29			23
Fixed income		15			15			14
Special situations		3			—			—
Real estate investments		15			13			19
Private equity		10			10			10
Total		100	%		100	%		100	%

The investment strategy for plan assets related to the Company’s defined benefit plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

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NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active Markets for			Significant Other			Significant
	Identical			Observable			Unobservable
	Assets			Inputs			Inputs
As of December 31, 2009:	(Level 1)			(Level 2)			(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	1,117		$	462		$	—	$	1,579
International equity*		1,444			144			—		1,588
Fixed income:
U.S. Treasury, government, and agency bonds		—			416			—		416
Mortgage- and asset-backed securities		—			113			—		113
Corporate bonds		—			279			—		279
Pooled funds		—			10			—		10
Cash equivalents and other		3			341			—		344
Special situations		—			—			—		—
Real estate investments		174			—			547		721
Private equity		—			—			555		555
Total	$	2,738		$	1,765		$	1,102	$	5,605
Liabilities:
Derivatives		(5	)		(1	)		—		(6	)
Total	$	2,733		$	1,764		$	1,102	$	5,599

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Southern Company and Subsidiary Companies 2009 Annual Report

	Fair Value Measurements Using
	Quoted Prices
	in Active Markets for			Significant Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	1,049		$	427	$	—	$	1,476
International equity*		944			87		—		1,031
Fixed income:
U.S. Treasury, government, and agency bonds		—			441		—		441
Mortgage- and asset-backed securities		—			209		—		209
Corporate bonds		—			286		—		286
Pooled funds		—			3		—		3
Cash equivalents and other		22			202		—		224
Special situations		—			—		—		—
Real estate investments		144			—		839		983
Private equity		—			—		490		490
Total	$	2,159		$	1,655	$	1,329	$	5,143
Liabilities:
Derivatives		(8	)		—		—		(8	)
Total	$	2,151		$	1,655	$	1,329	$	5,135

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
				(in millions)
Beginning balance	$	839		$	490	$	1,045		$	520
Actual return on investments:
Related to investments held at year end		(240	)		37		(170	)		(141	)
Related to investments sold during the year		(65	)		10		4			25
Total return on investments		(305	)		47		(166	)		(116	)
Purchases, sales, and settlements		13			18		(40	)		86
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	547		$	555	$	839		$	490

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

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Southern Company and Subsidiary Companies 2009 Annual Report

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the consolidated balance sheets related to the Company’s pension plans consist of the following:

	2009			2008
	(in millions)
Other regulatory assets, deferred	$	1,894		$	1,579
Other current liabilities		(25	)		(23	)
Employee benefit obligations		(1,106	)		(763	)
Accumulated other comprehensive income		74			54

Presented below are the amounts included in accumulated other comprehensive income and regulatory assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2010.

	Prior Service Cost		Net (Gain)Loss
	(in millions)
Balance at December 31, 2009:
Accumulated other comprehensive income	$	10	$	64
Regulatory assets		188		1,706
Total	$	198	$	1,770
Balance at December 31, 2008:
Accumulated other comprehensive income	$	12	$	42
Regulatory assets		220		1,359
Total	$	232	$	1,401
Estimated amortization in net periodic pension cost in 2010:
Accumulated other comprehensive income	$	1	$	1
Regulatory assets		31		9
Total	$	32	$	10

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NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

The components of other comprehensive income, along with the changes in the balances of regulatory assets and regulatory liabilities, related to the defined benefit pension plans for the year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Accumulated Other			Regulatory			Regulatory
	Comprehensive Income			Assets			Liabilities
	(in millions)
Balance at December 31, 2007	$	(26	)	$	188		$	(1,288	)
Net loss		83			1,412			1,322
Change in prior service costs		—			—			—
Reclassification adjustments:
Amortization of prior service costs		(2	)		(10	)		(34	)
Amortization of net gain		(1	)		(11	)		—
Total reclassification adjustments		(3	)		(21	)		(34	)
Total change		80			1,391			1,288
Balance at December 31, 2008		54			1,579			—
Net loss		21			355			—
Change in prior service costs		—			1			—
Reclassification adjustments:
Amortization of prior service costs		(1	)		(34	)		—
Amortization of net gain		—			(7	)		—
Total reclassification adjustments		(1	)		(41	)		—
Total change		20			315			—
Balance at December 31, 2009	$	74		$	1,894		$	—

Components of net periodic pension cost were as follows:

	2009			2008			2007
	(in millions)
Service cost	$	146		$	146		$	147
Interest cost		387			348			324
Expected return on plan assets		(541	)		(525	)		(481	)
Recognized net loss		7			9			10
Net amortization		35			37			35
Net periodic pension cost	$	34		$	15		$	35

Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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, 2009, estimated benefit payments were as follows:

	Benefit Payments
	(in millions)
2010	$	323
2011		341
2012		360
2013		383
2014		417
2015 to 2019		2,456

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Southern Company and Subsidiary Companies 2009 Annual Report

Other Postretirement Benefits

Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,733		$	1,797
Service cost		26			36
Interest cost		113			138
Benefits paid		(93	)		(108	)
Actuarial loss (gain)		34			(139	)
Plan amendments		(59	)		—
Retiree drug subsidy		5			9
Balance at end of year		1,759			1,733
Change in plan assets
Fair value of plan assets at beginning of year		631			820
Actual return (loss) on plan assets		127			(232	)
Employer contributions		72			142
Benefits paid		(87	)		(99	)
Fair value of plan assets at end of year		743			631
Accrued liability	$	(1,016	)	$	(1,102	)

Other postretirement benefit 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. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		42	%		37	%		34	%
International equity		19			24			18
Fixed income		30			32			38
Special situations		1			—			—
Real estate investments		5			4			7
Private equity		3			3			3
Total		100	%		100	%		100	%

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Trust-owned life insurance.Some of the Company’s taxable trusts invest in these investments in order to minimize the impact of taxes on the portfolio.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

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Southern Company and Subsidiary Companies 2009 Annual Report

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
				(in millions)
Assets:
Domestic equity*	$	149	$	42	$	—	$	191
International equity*		62		36		—		98
Fixed income:
U.S. Treasury, government, and agency bonds		—		22		—		22
Mortgage- and asset-backed securities		—		5		—		5
Corporate bonds		—		12		—		12
Pooled funds		—		18		—		18
Cash equivalents and other		—		54		—		54
Trust-owned life insurance		—		270		—		270
Special situations		—		—		—		—
Real estate investments		7		—		24		31
Private equity		—		—		24		24
Total	$	218	$	459	$	48	$	725

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2008:	(Level 1)		(Level 2)		(Level 3)		Total
				(in millions)
Assets:
Domestic equity*	$	114	$	47	$	—	$	161
International equity*		41		24		—		65
Fixed income:
U.S. Treasury, government, and agency bonds		—		23		—		23
Mortgage- and asset-backed securities		—		9		—		9
Corporate bonds		—		12		—		12
Pooled funds		—		9		—		9
Cash equivalents and other		1		73		—		74
Trust-owned life insurance		—		215		—		215
Special situations		—		—		—		—
Real estate investments		6		—		36		42
Private equity		—		—		21		21
Total	$	162	$	412	$	57	$	631

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Southern Company and Subsidiary Companies 2009 Annual Report

Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in millions)
Beginning balance	$	36		$	21	$	44		$	22
Actual return on investments:
Related to investments held at year end		(10	)		2		(6	)		(6	)
Related to investments sold during the year		(3	)		—		—			1
Total return on investments		(13	)		2		(6	)		(5	)
Purchases, sales, and settlements		1			1		(2	)		4
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	24		$	24	$	36		$	21

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:

	2009			2008
	(in millions)
Other regulatory assets, deferred	$	374		$	489
Other current liabilities		—			(3	)
Employee benefit obligations		(1,016	)		(1,099	)
Accumulated other comprehensive income		5			8

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Southern Company and Subsidiary Companies 2009 Annual Report

Presented below are the amounts included in accumulated other comprehensive income and regulatory assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2010.

	Prior Service		Net (Gain)		Transition
	Cost		Loss		Obligation
	(in millions)
Balance at December 31, 2009:
Accumulated other comprehensive income	$	—	$	5	$	—
Regulatory assets		41		298		35
Total	$	41	$	303	$	35
Balance at December 31, 2008:
Accumulated other comprehensive income	$	3	$	5	$	—
Regulatory assets		88		335		66
Total	$	91	$	340	$	66
Estimated amortization as net periodic postretirement benefit cost in 2010:
Accumulated other comprehensive income	$	—	$	—	$	—
Regulatory assets		5		5		10
Total	$	5	$	5	$	10

The components of other comprehensive income, along with the changes in the balance of regulatory assets, related to the other postretirement benefit plans for the plan year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Accumulated Other			Regulatory
	Comprehensive Income			Assets
	(in millions)
Balance at December 31, 2007	$	8		$	360
Net loss		1			166
Change in prior service costs/transition obligation		—			—
Reclassification adjustments:
Amortization of transition obligation		—			(18	)
Amortization of prior service costs		(1	)		(11	)
Amortization of net gain		—			(8	)
Total reclassification adjustments		(1	)		(37	)
Total change		—			129
Balance at December 31, 2008		8			489
Net loss (gain)		—			(33	)
Change in prior service costs/transition obligation		(3	)		(56	)
Reclassification adjustments:
Amortization of transition obligation		—			(13	)
Amortization of prior service costs		—			(8	)
Amortization of net gain		—			(5	)
Total reclassification adjustments		—			(26	)
Total change		(3	)		(115	)
Balance at December 31, 2009	$	5		$	374

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Southern Company and Subsidiary Companies 2009 Annual Report

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

	2009			2008			2007
	(in millions)
Service cost	$	26		$	28		$	27
Interest cost		113			111			107
Expected return on plan assets		(61	)		(59	)		(52	)
Net amortization		25			31			38
Net postretirement cost	$	103		$	111		$	120

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced Southern Company’s expenses for the years ended December 31, 2009, 2008, and 2007 by approximately $33 million, $35 million, and $35 million, respectively.

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 Payments		Subsidy Receipts			Total
	(in millions)
2010	$	107	$	(8	)	$	99
2011		117		(9	)		108
2012		123		(11	)		112
2013		129		(12	)		117
2014		134		(14	)		120
2015 to 2019		722		(93	)		629

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual salary increase of 3.50%.

	2009			2008			2007
Discount rate:
Pension plans		5.93	%		6.75	%		6.30	%
Other postretirement benefit plans		5.83			6.75			6.30
Annual salary increase		4.18			3.75			3.75
Long-term return on plan assets:
Pension plans		8.50			8.50			8.50
Other postretirement benefit plans		7.51			7.59			7.58

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.

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Southern Company and Subsidiary Companies 2009 Annual Report

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2009 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	115	$	102
Service and interest costs		9		9

Employee Savings Plan

Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $78 million, $76 million, and $73 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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) was an energy company with businesses that included 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 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 in December 2005, and Mirant announced that this plan became effective in January 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).

Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for certain costs. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. If Southern Company’s claims for indemnification with respect to these costs are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. As a result of the $202 million settlement on March 31, 2009 of another suit related to Mirant (MC Asset Recovery litigation), the maximum amount Southern Company can assert by proof of claim in the Mirant bankruptcy is capped at $9.5 million. See Note 5 under “Effective Tax Rate” for more information regarding the MC Asset Recovery settlement. The final outcome of this matter cannot now be determined.

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Southern Company and Subsidiary Companies 2009 Annual Report

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. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

Southern Company believes that the traditional 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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly

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Southern Company and Subsidiary Companies 2009 Annual Report

and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but the traditional operating companies and Southern Power were named as defendants in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

Southern Company’s subsidiaries must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.

Georgia Power’s environmental remediation liability as of December 31, 2009 was $12.5 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.

By letter dated September 30, 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Southern Company’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $65.2 million as of December 31, 2009. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential 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 through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.

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.

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Southern Company and Subsidiary Companies 2009 Annual Report

FERC Matters

Market-Based Rate Authority

Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that any subsidiary of Southern Company possesses or has exercised any market power. The agreement likewise does not require Southern Company to make any refunds related to sales during the 15-month refund period. The agreement does provide for the traditional operating companies and Southern Power to donate a total of $1.7 million to nonprofit organizations in the states in which they operate for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The Company’s generation fleet in its retail service territory is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Mississippi Power, 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 believes that its subsidiaries have complied with applicable laws and that the plaintiffs’ claims are without merit.

To date, Mississippi Power has entered into agreements with plaintiffs in approximately 95% 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 the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s financial statements.

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Southern Company and Subsidiary Companies 2009 Annual Report

In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fibernet, Inc., a subsidiary of telecommunications company ITC DeltaCom, Inc. 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.

The final outcome of these matters cannot now be determined.

Nuclear Fuel Disposal Costs

Alabama Power and Georgia Power have contracts with the United States, acting through the U.S. Department of Energy (DOE), which 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.

In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal. In April 2008, the U.S. Court of Appeals for the Federal Circuit granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. The U.S. Court of Appeals for the Federal Circuit has left the stay of appeals in place pending the decision in an appeal of another case involving spent nuclear fuel contracts.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2009 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. 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 Plants Hatch and Farley, on-site dry storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.

Income Tax Matters

Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. See Note 5 under “Unrecognized Tax Benefits” for additional information. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. The ultimate outcome of this matter cannot now be determined.

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Southern Company and Subsidiary Companies 2009 Annual Report

Retail Regulatory Matters

Alabama Power

Retail Rate Plans

Alabama Power operates under a Rate Stabilization and Equalization Plan (Rate RSE) approved by the Alabama PSC. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. Retail rates remain unchanged when the retail return on common equity (ROE) is projected to be between 13% and 14.5%. 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 ROE fall below the allowed equity return range. In October 2008, the Alabama PSC approved a corrective rate package effective January 2009, that primarily provides for adjustments associated with customer charges to certain existing rate structures. Alabama Power agreed to a moratorium on any increase in rates in 2009 under Rate RSE. On December 1, 2009, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2010. The Rate RSE increase for 2010 is 3.2%, or $152 million annually, and became effective in January 2010. The revenue adjustment under the Rate RSE is largely attributable to the costs associated with fossil capacity which is currently dedicated to certain long-term wholesale contracts that expire during 2010. Retail cost of service for 2010 reflects the costs for that portion of the year in which this capacity is no longer committed to wholesale. In an Alabama PSC order dated January 5, 2010, the Alabama PSC acknowledged that a full calendar year of costs for such capacity would be reflected in the Rate RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the maximum increase for 2011 cannot exceed 4.76%.

The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the cost of placing new generating facilities in retail service and for the recovery of retail costs associated with certificated power purchase agreements (PPAs) under a Rate Certificated New Plant (Rate CNP). There was no adjustment to Rate CNP in April 2007, 2008, or 2009. Effective April 2010, Rate CNP will be reduced approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. Rate CNP also allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 2.4% in January 2008 and 0.6% in January 2007 due to environmental costs. In October 2008, Alabama Power agreed to defer collection during 2009 of any increase in rates under this portion of Rate CNP which permits recovery of costs associated with environmental laws and regulations until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on Southern Company’s revenues or net income in 2009. On December 1, 2009, Alabama Power made its Rate CNP environmental submission to the Alabama PSC of projected data for calendar year 2010. The Rate CNP environmental increase for 2010 is 4.3%, or $195 million annually, based upon projected billings. Under the terms of the rate mechanism, the adjustment became effective in January 2010. The Rate CNP environmental adjustment is primarily attributable to scrubbers being placed in service during 2010 at four of Alabama Power’s generating plants.

Fuel Cost Recovery

Alabama Power has established fuel cost recovery rates under an energy cost recovery clause (Rate ECR) approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. In June 2007, the Alabama PSC approved Alabama Power’s request to increase the retail energy cost recovery rate to 3.100 cents per kilowatt hour (KWH), effective with billings beginning July 2007. In October 2008, the Alabama PSC approved an increase in Alabama Power’s Rate ECR factor to 3.983 cents per KWH effective with billings beginning October 2008. On June 2, 2009, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor to 3.733 cents per KWH for billings beginning June 9, 2009. On December 1, 2009, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor to 2.731 cents per KWH for billings beginning January 2010 through December 2011. The Alabama PSC further approved an additional reduction in the Rate ECR factor of 0.328 cents per KWH for the billing months of January 2010 through December 2010 resulting in a Rate ECR factor of 2.403 cents per KWH for such 12-month period. For billing months beginning January 2012, the Rate ECR factor shall be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, the approved decreases in the Rate ECR factor will have no significant effect on Southern Company’s net income, but will decrease operating cash flows related to fuel cost recovery in 2010 when compared to 2009. As of December 31, 2009, Alabama Power had an over recovered fuel balance of approximately $200 million, of which approximately $22 million is included in other regulatory liabilities, deferred in the balance sheets. Alabama Power, along with the Alabama PSC, will continue to monitor the over recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.

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Southern Company and Subsidiary Companies 2009 Annual Report

Georgia Power

Retail Rate Plans

In December 2004, the Georgia PSC approved the 2004 Retail Rate Plan. Under the terms of the 2004 Retail Rate Plan, Georgia Power’s earnings were evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees 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 2007, Georgia Power refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to earnings for 2007.

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail ROE range of 10.25% to 12.25%. Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs related to environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. In connection with the 2007 Retail Rate Plan, Georgia Power agreed that it would not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Georgia Power is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued.

Cost of Removal

The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, Georgia Power’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations.

On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail ROE. For the year ended December 31, 2009, Georgia Power amortized $41 million of the regulatory liability. In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in Georgia Power’s total annual billings of approximately $383 million effective March 1, 2007 and approximately $222 million effective June 1, 2008. On December 15, 2009, Georgia Power filed for a fuel cost recovery increase with the Georgia PSC. On February 22, 2010, Georgia Power, the Georgia PSC Public Interest Advocacy Staff, and three customer groups entered into a stipulation to resolve the case, subject to approval by the Georgia PSC (the Stipulation). Under the terms of the Stipulation, Georgia Power’s annual fuel cost recovery billings will increase by approximately $425 million. In addition, Georgia Power will implement an interim fuel rider, which would allow Georgia Power to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more than $75 million. Georgia Power is required to file its next fuel case by March 1, 2011. The Georgia PSC is scheduled to vote on the Stipulation on March 11, 2010 with the new fuel rates to become effective April 1, 2010. The ultimate outcome of this matter cannot be determined at this time.

As of December 31, 2009, Georgia Power’s under recovered fuel balance totaled approximately $665 million, which if the Stipulation is approved, Georgia Power will recover over 32 months beginning April 1, 2010. Therefore, approximately $373 million of the under recovered regulatory clause revenues for Georgia Power is included in deferred charges and other assets at December 31, 2009.

Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on Southern Company’s revenues or net income, but does impact annual cash flow.

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Southern Company and Subsidiary Companies 2009 Annual Report

Nuclear Construction

On August 26, 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). See Note 4 for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively.

In April 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including certain index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share is 45.7%.

On February 23, 2010, Georgia Power, acting for itself and as agent for the Owners, and the Consortium entered into an amendment to the Vogtle 3 and 4 Agreement. The amendment, which is subject to the approval of the Georgia PSC, replaces certain of the index-based adjustments to the purchase price with fixed escalation amounts.

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base.

On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective on January 1, 2011. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion.

On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. Georgia Power believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions.

On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds.

On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any proposed change to the estimated construction cost as certified by the Georgia PSC in March 2009. On February 25, 2010, the Georgia PSC approved the expenditures made by Georgia Power pursuant to the certification through June 30, 2009. The Georgia PSC also ordered that in its future semi-annual construction monitoring reports, Georgia Power will report against a total certified cost of approximately $6.1 billion, which is the effective certified amount after giving effect to the Georgia Nuclear Energy Financing Act as described above. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

The ultimate outcome of these matters cannot now be determined.

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Southern Company and Subsidiary Companies 2009 Annual Report

Integrated Coal Gasification Combined Cycle (IGCC)

On January 16, 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. The plant would utilize an advanced integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined lignite from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. The Mississippi PSC has issued orders allowing Mississippi Power to defer the costs associated with the generation resource planning, evaluation, and screening activities as a regulatory asset. As of December 31, 2009, Mississippi Power had spent a total of $73.5 million of such costs including regulatory filing costs.

On November 9, 2009, the Mississippi PSC issued an order that found Mississippi Power has a demonstrated need for additional capacity. Hearings to determine the appropriate resource to fill the need were held in February 2010 with a decision due by May 2010.

The ultimate outcome of this matter cannot now be determined.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities jointly with Power South Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with OPC, MEAG Power, 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 Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.

At December 31, 2009, 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:

	Percent			Amount of		Accumulated
	Ownership			Investment		Depreciation
				(in millions)
Plant Vogtle (nuclear) Units 1 and 2		45.7	%	$	3,285	$	1,916
Plant Hatch (nuclear)		50.1			937		522
Plant Miller (coal) Units 1 and 2		91.8			1,063		449
Plant Scherer (coal) Units 1 and 2		8.4			133		70
Plant Wansley (coal)		53.5			696		195
Rocky Mountain (pumped storage)		25.4			175		106
Intercession City (combustion turbine)		33.3			12		3
Plant Stanton (combined cycle) Unit A		65.0			151		20

At December 31, 2009, the portion of total construction work in progress related to Plants Miller, Scherer, Wansley, and Vogtle Units 3 and 4 was $244 million, $247 million, $5 million, and $611 million, respectively. Construction at Plants Miller, Wansley, and Scherer relates primarily to environmental projects. See Note 3 under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” for information on Plant Vogtle Units 3 and 4.

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 and each company is responsible for providing its own financing.

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Southern Company and Subsidiary Companies 2009 Annual Report

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.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2009			2008		2007
	(in millions)
Federal —
Current	$	771		$	628	$	715
Deferred		40			177		11
		811			805		726
State —
Current		100			72		114
Deferred		(15	)		38		(5	)
		85			110		109
Total	$	896		$	915	$	835

Net cash payments for income taxes in 2009, 2008, and 2007 were $975 million, $537 million, and $732 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:

	2009			2008
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	5,938		$	5,356
Property basis differences		986			968
Leveraged lease basis differences		251			306
Employee benefit obligations		384			364
Under recovered fuel clause		271			516
Premium on reacquired debt		100			107
Regulatory assets associated with employee benefit obligations		939			869
Regulatory assets associated with asset retirement obligations		486			480
Other		216			132
Total		9,571			9,098
Deferred tax assets —
Federal effect of state deferred taxes		302			354
State effect of federal deferred taxes		108			105
Employee benefit obligations		1,435			1,325
Over recovered fuel clause		119			—
Other property basis differences		132			144
Deferred costs		65			99
Cost of removal		109			—
Unbilled revenue		96			100
Other comprehensive losses		81			82
Asset retirement obligations		486			480
Other		458			279
Total		3,391			2,968
Total deferred tax liabilities, net		6,180			6,130
Portion included in prepaid expenses (accrued income taxes), net		229			(90	)
Deferred state tax assets		105			103
Valuation allowance		(59	)		(63	)
Accumulated deferred income taxes	$	6,455		$	6,080

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Southern Company and Subsidiary Companies 2009 Annual Report

At December 31, 2009, Southern Company had a State of Georgia net operating loss (NOL) carryforward totaling $1.0 billion, which could result in net state income tax benefits of $55 million, if utilized. However, Southern Company has established a valuation allowance for the potential $55 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 2010 and 2021. During 2009, Southern Company utilized $4 million in available NOLs, which resulted in a $0.2 million state income tax benefit. The State of Georgia allows the filing of a combined return, which should substantially reduce any additional NOL carryforwards.

At December 31, 2009, the tax-related regulatory assets and liabilities were $1.05 billion and $249 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.

Effective Tax Rate

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 and preference dividends of subsidiaries, as a result of the following:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		2.1			2.6			2.7
Synthetic fuel tax credits		—			—			(1.4	)
Employee stock plans dividend deduction		(1.4	)		(1.3	)		(1.3	)
Non-deductible book depreciation		0.9			0.8			0.9
Difference in prior years’ deferred and current tax rate		(0.1	)		(0.2	)		(0.2	)
AFUDC-Equity		(2.7	)		(1.9	)		(1.4	)
Production activities deduction		(0.7	)		(0.4	)		(0.8	)
Leveraged lease termination		(0.9	)		—			—
MC Asset Recovery		2.7			—			—
Donations		(0.4	)		—			(0.8	)
Other		(0.1	)		(1.0	)		(0.8	)
Effective income tax rate		34.4	%		33.6	%		31.9	%

Southern Company’s 2009 effective tax rate increased from 2008 primarily due to the $202 million charge recorded for the MC Asset Recovery litigation settlement, which completed and resolved all claims by MC Asset Recovery against Southern Company. Southern Company is currently evaluating potential recovery of the settlement payment through various means. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time. The increase in Southern Company’s effective tax rate was partially offset by the gain on the early termination of an international leveraged lease investment and the increase in AFUDC related to increased construction expenditures.

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U. S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, Southern Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

For 2009, Georgia Power donated 5,111 acres of land to the State of Georgia. In 2007, Georgia Power donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia. The estimated value of the donations lowered the effective income tax rate for the years ended December 31, 2009 and December 31, 2007.

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Southern Company and Subsidiary Companies 2009 Annual Report

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits increased by $53 million, resulting in a balance of $199 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009			2008			2007
	(in millions)
Unrecognized tax benefits at beginning of year	$	146		$	264		$	211
Tax positions from current periods		53			49			46
Tax positions from prior periods		2			130			7
Reductions due to settlements		—			(297	)		—
Reductions due to expired statute of limitations		(2	)		—			—
Balance at end of year	$	199		$	146		$	264

The tax positions from current periods increase for 2009 relate primarily to the Georgia state tax credits litigation, the production activities deduction tax position, and other miscellaneous uncertain tax positions. The tax positions increase from prior periods for 2009 relates primarily to the production activities deduction tax position. See Note 3 under “Income Tax Matters” for additional information.

Impact on Southern Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
	(in millions)
Tax positions impacting the effective tax rate	$	199	$	143	$	96
Tax positions not impacting the effective tax rate		—		3		168
Balance of unrecognized tax benefits	$	199	$	146	$	264

The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. See Note 3 under “Income Tax Matters” for additional information.

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008			2007
	(in millions)
Interest accrued at beginning of year	$	15	$	31		$	27
Interest reclassified due to settlements		—		(49	)		—
Interest accrued during the year		6		33			4
Balance at end of year	$	21	$	15		$	31

Southern Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued during 2009 was primarily associated with the Georgia state tax credit litigation.

Southern Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of Southern Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the Georgia state tax credits litigation and/or the conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

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Southern Company and Subsidiary Companies 2009 Annual Report

6. FINANCING

Long-Term Debt Payable to Affiliated Trusts

Certain of the traditional operating companies have 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 applicable traditional operating company through the issuance of junior subordinated notes totaling $412 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as “Long-term Debt.” Such traditional 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, 2009, preferred securities of $400 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 scheduled maturities and redemptions of securities due within one year at December 31 was as follows:

	2009		2008
	(in millions)
Capitalized leases	$	21	$	20
Senior notes		1,090		565
Other long-term debt		2		32
Total	$	1,113	$	617

Maturities through 2014 applicable to total long-term debt are as follows: $1.1 billion in 2010; $1.1 billion in 2011; $1.8 billion in 2012; $941 million in 2013; and $430 million in 2014.

Bank Term Loans

Certain of the traditional operating companies have entered into bank term loan agreements. In 2008, Georgia Power borrowed $300 million under a three-year term loan agreement. In 2008, Gulf Power borrowed $110 million under a three-year loan agreement. Mississippi Power also borrowed $80 million under a three-year term loan agreement in 2008. The proceeds of these loans were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes.

Senior Notes

Southern Company and its subsidiaries issued a total of $2.4 billion of senior notes in 2009. Southern Company issued $650 million, and the traditional operating companies’ combined issuances totaled $1.8 billion. The proceeds of these issuances were used to repay long-term and short-term indebtedness and for other general corporate purposes.

At December 31, 2009 and 2008, Southern Company and its subsidiaries had a total of $14.7 billion and $12.9 billion, respectively, of senior notes outstanding. At December 31, 2009 and 2008, Southern Company had a total of $1.8 billion and $1.1 billion, respectively, of senior notes outstanding.

Pollution Control Revenue Bonds

Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The traditional operating companies have $3.6 billion of outstanding pollution control revenue bonds and are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

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Southern Company and Subsidiary Companies 2009 Annual Report

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 and Gulf Power have granted one or more liens on certain of their respective property in connection with the issuance of certain pollution control revenue bonds with an outstanding principal amount of $194 million. 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 December 31, 2009, unused credit arrangements with banks totaled $4.8 billion, of which $1.5 billion expires during 2010, $25 million expires in 2011, and $3.2 billion expires in 2012. The following table outlines the credit arrangements by company:

					Executable
					Term-Loans				Expires
					One		Two
Company	Total		Unused		Year		Years		2010		2011		2012
					(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	—	$	950
Alabama Power		1,271		1,271		372		—		481		25		765
Georgia Power		1,715		1,703		—		40		595		—		1,120
Gulf Power		220		220		70		—		220		—		—
Mississippi Power		156		156		15		41		156		—		—
Southern Power		400		400		—		—		—		—		400
Other		60		60		60		—		60		—		—
Total	$	4,772	$	4,760	$	517	$	81	$	1,512	$	25	$	3,235

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 average approximately¹/2 of 1% or less for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal.

Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities. At December 31, 2009, Southern Company, Southern Power, and the traditional operating companies were each in compliance with their respective debt limit covenants.

In addition, the credit arrangements typically contain cross default provisions that would be triggered if the borrower defaulted on other indebtedness above a specified threshold. 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.

A portion of the $4.8 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2009 was approximately $1.6 billion. Subsequent to December 31, 2009, two remarketings of pollution control revenue bonds increased the total requiring liquidity support to $1.8 billion.

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company and the traditional operating companies may also borrow through various other arrangements with banks. The amounts of commercial paper outstanding and included in notes payable in the balance sheets at December 31, 2009 and December 31, 2008 were $638 million and $794 million, respectively. The amounts of short-term bank loans included in notes payable in the balance sheets at December 31, 2008 were $150 million. There were no short term-bank loans included in notes payable in the balance sheet at December 31, 2009.

During 2009, the peak amount outstanding for short-term debt was $1.4 billion, and the average amount outstanding was $956 million. The average annual interest rate on short-term debt was 0.4% for 2009 and 2.7% for 2008.

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Changes in Redeemable Preferred Stock of Subsidiaries

Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as “Redeemable Preferred Stock of Subsidiaries” in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary’s board. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are required to be shown as “noncontrolling interest,” separately presented as a component of “Stockholders’ Equity” on Southern Company’s consolidated balance sheets, consolidated statements of capitalization, and consolidated statements of stockholders’ equity.

The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:

	Redeemable Preferred Stock
	of Subsidiaries
	(in millions)
Balance at December 31, 2006	$	498
Issued		—
Redeemed		—
Balance at December 31, 2007	$	498
Issued		—
Redeemed		(125	)
Other		2
Balance at December 31, 2008	$	375
Issued		—
Redeemed		—
Balance at December 31, 2009	$	375

7. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently estimated to total $4.9 billion in 2010, $5.3 billion in 2011, and $6.2 billion in 2012. These amounts include $271 million, $157 million, and $166 million in 2010, 2011, and 2012, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel 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 these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2009, significant purchase commitments were outstanding in connection with the ongoing construction program, which includes new facilities and capital improvements to transmission, distribution, and generation facilities, including those to meet environmental standards. See Note 3 under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” for additional information.

Long-Term Service Agreements

The traditional operating companies and Southern Power have entered into Long-Term Service Agreements (LTSAs) with General Electric (GE), Alstom Power, Inc., Mitsubishi Power Systems Americas, Inc., and Siemens AG for the purpose of securing maintenance support for the combined cycle and combustion turbine generating facilities owned or under construction by the subsidiaries. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs are also obligated to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.

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In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments under the LTSAs, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments under these agreements for facilities owned are currently estimated at $2.4 billion over the remaining life of the agreements, which are currently estimated to range up to 24 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 neutron monitoring system parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are currently estimated at $8 million. The contract contains cancellation provisions at the option of Georgia Power.

Payments made under the LTSAs prior to the performance of any work are recorded as a prepayment in the balance sheets. All work performed is capitalized or charged to expense (net of any joint owner billings), as appropriate based on the nature of the work.

Limestone Commitments

As part of Southern Company’s program to reduce sulfur dioxide emissions from its coal plants, the traditional operating companies have entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. Southern Company has a minimum contractual obligation of 7.0 million tons, equating to approximately $295 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $37 million in 2010, $36 million in 2011, $37 million in 2012, $38 million in 2013, and $39 million in 2014.

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, biomass fuel, 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 and nitrogen oxide emissions 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, 2009. Also, Southern Company has entered into various long-term commitments for the purchase of capacity and electricity. Total estimated minimum long-term obligations at December 31, 2009 were as follows:

	Commitments
	Natural Gas		Coal		Nuclear Fuel		Biomass Fuel		Purchased Power*
	(in millions)
2010	$	1,349	$	4,490	$	271	$	—	$	253
2011		1,266		3,135		157		—		258
2012		926		1,572		166		17		266
2013		816		1,063		148		17		235
2014		688		850		83		18		267
2015 and thereafter		4,153		2,508		297		128		2,742
Total	$	9,198	$	13,618	$	1,122	$	180	$	4,021

* Certain PPAs reflected in the table are accounted for as operating leases.

Additional commitments for fuel will be required to supply Southern Company’s future needs. Total charges for nuclear fuel included in fuel expense amounted to $160 million in 2009, $147 million in 2008, and $144 million in 2007.

Operating Leases

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), whose partners are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% 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

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renewal option based on the cost of the facility at the inception of the lease. Mississippi Power is required to amortize approximately 4% of the initial acquisition cost over the initial lease term. In April 2010, 18 months prior to the end of the initial lease term, Mississippi Power must notify Juniper if the lease will be terminated. Mississippi Power may elect to renew the lease for 10 years. If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17% 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. If Mississippi Power does not exercise either its purchase option or its renewal option, Mississippi Power could lose its rights to some or all of the 1,064 MWs of capacity at that time.

The lease provides for a residual value guarantee, approximately 73% 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 $3 million, $5 million, and $7 million for the fair market value of this residual value guarantee is included in the balance sheets as of December 31, 2009, 2008, and 2007, respectively.

Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $186 million, $184 million, and $187 million for 2009, 2008, and 2007, respectively. Southern 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.

At December 31, 2009, estimated minimum lease payments for noncancelable operating leases were as follows:

	Minimum Lease Payments
	Plant Daniel		Barges & Rail Cars		Other		Total
	(in millions)
2010	$	28	$	70	$	46	$	144
2011		28		57		38		123
2012		—		40		29		69
2013		—		32		22		54
2014		—		27		18		45
2015 and thereafter		—		28		96		124
Total	$	56	$	254	$	249	$	559

For the traditional operating companies, a majority of the barge and 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 2010, 2011, and 2013, and the maximum obligations are $61 million, $40 million, and $19 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. However, due to the recessionary economy, it is possible that the fair market value of the leased property would not eliminate the payments under the residual value obligations on the leases expiring in 2010.

Guarantees

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

In 2009, Southern Company issued 22.6 million shares of common stock for $673 million through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued 19.9 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $613 million, net of $6 million in fees and commissions. In 2008, Southern Company raised $474 million from the issuance of 14.1 million new common shares through the Southern Investment Plan and employee and director stock plans.

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Shares Reserved

At December 31, 2009, a total of 91 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes the stock option plan discussed below).

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, 2009, there were 7,563 current and former employees participating in the stock option plan, and there were 21 million shares of common stock remaining available for awards under this plan. 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. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. 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. For certain stock option awards, a change in control will provide accelerated vesting.

The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:

Year Ended December 31	2009			2008			2007
Expected volatility		15.6	%		13.1	%		14.8	%
Expected term(in years)		5.0			5.0			5.0
Interest rate		1.9	%		2.8	%		4.6	%
Dividend yield		5.4	%		4.5	%		4.3	%
Weighted average grant-date fair value	$1.80			$	2.37		$	4.12

Southern Company’s activity in the stock option plan for 2009 is summarized below:

	Shares Subject			Weighted Average
	To Option			Exercise Price
Outstanding at December 31, 2008		36,941,273		$	32.09
Granted		12,292,239			31.38
Exercised		(879,555	)		21.97
Cancelled		(106,638	)		32.48
Outstanding at December 31, 2009		48,247,319		$	32.10
Exercisable at December 31, 2009		30,209,272		$	31.57

The number of stock options vested, and expected to vest in the future, as of December 31, 2009 was not significantly different from the number of stock options outstanding at December 31, 2009 as stated above. As of December 31, 2009, the weighted average remaining contractual term for the options outstanding and options exercisable was 6 years and 5 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $100 million and $77 million, respectively.

As of December 31, 2009, there was $6 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.

For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option awards recognized in income was $23 million, $20 million, and $28 million, respectively, with the related tax benefit also recognized in income of $9 million, $8 million, and $11 million, respectively.

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The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $9 million, $45 million, and $81 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $4 million, $17 million, and $31 million, respectively, for the years ended December 31, 2009, 2008, and 2007.

Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2009, 2008, and 2007 was $19 million, $113 million, and $195 million, respectively.

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
	2009		2008		2007
	(in thousands)
As reported shares		794,795		771,039		756,350
Effect of options		1,620		3,809		4,666
Diluted shares		796,415		774,848		761,016

The reduction in the effect of options for the years ended December 31, 2009 and 2008 compared to 2007 is primarily due to the anti-dilutive nature of certain stock options outstanding that have an exercise price that exceeds the average stock price of Southern Company shares in the year ended December 31, 2009 and 2008, respectively. At December 31, 2009 and 2008, there were 37.7 million and 6.8 million stock options outstanding, respectively, that were not included in the diluted earnings per share calculation because they were anti-dilutive. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options for the years ended December 31, 2009 and 2008 would have increased by 3.4 million and 0.3 million shares, respectively.

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2009, consolidated retained earnings included $5.6 billion of undistributed retained earnings of the subsidiaries. Southern Power’s credit facility contains potential limitations on the payment of common stock dividends; as of December 31, 2009, Southern Power was in compliance with all such requirements.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments 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 $12.6 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 $375 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 commercial nuclear reactors. A company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 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 $235 million and $237 million, respectively, per incident, but not more than an aggregate of $35 million per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013.

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. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses.

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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 deductible 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 $38 million and $50 million, respectively.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

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. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

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As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
				(in millions)
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Interest rate derivatives		—		3		—		3
Nuclear decommissioning trusts:(a)
Domestic equity		724		50		—		774
U.S. Treasury and government agency securities		11		36		—		47
Municipal bonds		—		23		—		23
Corporate bonds		—		137		—		137
Mortgage and asset backed securities		—		65		—		65
Other		—		22		—		22
Cash equivalents and restricted cash		623		—		—		623
Other		3		48		35		86
Total	$	1,361	$	391	$	35	$	1,787
Liabilities:
Energy-related derivatives	$	—	$	185	$	—	$	185
Interest rate derivatives		—		6		—		6
Total	$	—	$	191	$	—	$	191

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 11 for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. See Note 1 under “Nuclear Decommissioning” for additional information. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. “Other” represents marketable securities and certain deferred compensation funds also invested in various marketable securities. All of these financial instruments and investments are valued primarily using the market approach.

As of December 31, 2009, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

	Fair		Unfunded	Redemption	Redemption
As of December 31, 2009:	Value		Commitments	Frequency	Notice Period
	(in millions)
Nuclear decommissioning trusts:
Corporate bonds – commingled funds	$	14	None	Daily		1 to 3 days
Other – commingled funds		13	None	Daily	Not applicable
Trust owned life insurance		78	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		623	None	Daily	Not applicable
Other:
Deferred compensation — money market funds		3	None	Daily	Not applicable

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The commingled funds in the nuclear decommissioning trusts invest primarily in a diversified portfolio of investment high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity.

One of the nuclear decommissioning trusts includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the tables above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company’s investment in the money market funds.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at December 31, 2009 and 2008 are as follows:

	Level 3
	Other
	(in millions)
Beginning balance at December 31, 2008	$	35
Total gains (losses) — realized/unrealized:
Included in earnings		(3	)
Included in other comprehensive income		3
Ending balance at December 31, 2009	$	35

Unrealized losses of $3 million were included in earnings during 2009 relating to assets still held at December 31, 2009 and are recorded in “depreciation and amortization.”

As of December 31, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2009	$	19,145	$	19,567
2008	$	17,327	$	17,114

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

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11. DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

The traditional 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 traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of three methods:

• Regulatory Hedges– Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

• Cash Flow Hedges– Gains and losses on energy-related derivatives designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income (OCI) before being recognized in income in the same period as the hedged transactions are reflected in earnings.

• Not Designated– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

II-89

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

At December 31, 2009, the net volume of energy-related derivative contracts for power and natural gas positions for Southern Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Power					Gas
	Longest		Longest		Net			Longest		Longest
Net Sold	Hedge		Non-Hedge		Purchased			Hedge		Non-Hedge
Megawatt-hours	Date		Date		mmBtu			Date		Date
(in millions)					(in millions)
2.6		2010		2010		154	*		2014		2014

* Includes location basis of 2 million British thermal units (mmBtu).

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2010 are immaterial.

Interest Rate Derivatives

Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings.

At December 31, 2009, Southern Company had a total of $976 million notional amount of interest rate derivatives outstanding with net fair value losses of $3 million as follows:

				Weighted				Fair Value
				Average				Gain (Loss)
	Notional		Variable Rate	Fixed Rate			Hedge Maturity	December 31,
	Amount		Received	Paid			Date	2009
	(in millions)							(in millions)
Cash flow hedges of existing debt
	$	576	SIFMA* Index		2.69	%	February 2010	$	(4	)
		300	1-month LIBOR		2.43	%	April 2010		(2	)
Cash flow hedges on forecasted debt
		100	3-month LIBOR		3.79	%	April 2020		3
Total	$	976						$	(3	)

* Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA)

For the year ended December 31, 2009, the Company had realized net losses of $19 million upon termination of certain interest rate derivatives at the same time the related debt was issued. The effective portion of these losses has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings.

The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2010 is $25 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037.

II-90

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

	Asset Derivatives							Liability Derivatives
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in millions)							(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:	Other current assets	$	1		$	10		Liabilities from risk management activities	$	111	$	215
	Other deferred charges and assets		1			—		Other deferred credits and liabilities		66		83
Total derivatives designated as hedging instruments for regulatory purposes		$	2		$	10			$	177	$	298
Derivatives designated as hedging instruments in cash flow hedges
Energy-related derivatives:	Other current assets	$	3		$	—		Liabilities from risk management activities	$	5	$	1
Interest rate derivatives:	Other current assets		3			—		Liabilities from risk management activities		6		37
	Other deferred charges and assets		—			—		Other deferred credits and liabilities		—		3
Total derivatives designated as hedging instruments in cash flow hedges		$	6		$	—			$	11	$	41
Derivatives not designated as hedging instruments
Energy-related derivatives:	Other current assets	$	2		$	12		Liabilities from risk management activities	$	3	$	8
Total		$	10		$	22			$	191	$	347
All derivative instruments are measured at fair value. See Note 10 for additional information. At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
	Unrealized Losses							Unrealized Gains
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in millions)							(in millions)
Energy-related derivatives:	Other regulatory assets, current	$	(111	)	$	(215	)	Other regulatory liabilities, current	$	1	$	10
	Other regulatory assets, deferred		(66	)		(83	)	Other regulatory liabilities, deferred		1		—
Total energy-related derivative gains (losses)		$	(177	)	$	(298	)		$	2	$	10

II-91

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in							Gain (Loss) Reclassified from Accumulated OCI into Income
Derivatives in Cash Flow	OCI on Derivative							(Effective Portion)
Hedging Relationships	(Effective Portion)								Amount
Derivative Category	2009	2008			2007			Statements of Income Location		2009	2008			2007
	(in millions)								(in millions)
Energy-related derivatives	$(2)	$	(1	)	$	(2	)	Fuel		$—	$	—		$	—
Interest rate derivatives	(5)		(47	)		(7	)	Interest expense		(46)		(19	)		(15	)
Total	$(7)	$	(48	)	$	(9	)			$(46)	$	(19	)	$	(15	)

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated	Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments		Amount
Derivative Category	Statements of Income Location	2009			2008			2007
		(in millions)
Energy-related derivatives:	Wholesale revenues	$	5		$	(2	)	$	—
	Fuel		(6	)		5			—
	Purchased power		(4	)		(2	)		—
	Other income (expense), net		—			—			30	*
Total		$	(5	)	$	1		$	30

* Includes a $27 million unrealized gain related to derivatives in place to reduce exposure to a phase-out of certain income tax credits related to synthetic fuel production in 2007.

Contingent Features

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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2009, the fair value of derivative liabilities with contingent features was $33 million.

At December 31, 2009, the Company had no collateral posted with their derivative counterparties. The maximum potential collateral requirement arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33 million. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to its debt.

II-92

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

12. SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $544 million, $638 million, and $547 million in 2009, 2008, and 2007, respectively. 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 telecommunications and leveraged lease projects. Also included are investments in synthetic fuels for 2007. 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:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
2009
Operating revenues	$	15,304	$	947	$	(609	)	$	15,642	$	165		$	(64	)	$	15,743
Depreciation and amortization		1,378		98		—			1,476		27			—			1,503
Interest income		21		—		—			21		3			(1	)		23
Interest expense		749		85		—			834		71			—			905
Income taxes		902		86		—			988		(92	)		—			896
Segment net income (loss)*		1,679		156		—			1,835		(193	)		1			1,643
Total assets		48,403		3,043		(143	)		51,303		1,223			(480	)		52,046
Gross property additions		4,568		331		—			4,899		14			—			4,913
2008
Operating revenues	$	16,521	$	1,314	$	(835	)	$	17,000	$	182		$	(55	)	$	17,127
Depreciation and amortization		1,325		89		—			1,414		29			—			1,443
Interest income		32		1		—			33		—			—			33
Interest expense		689		83		—			772		94			—			866
Income taxes		944		93		—			1,037		(122	)		—			915
Segment net income (loss)*		1,703		144		—			1,847		(104	)		(1	)		1,742
Total assets		44,794		2,813		(139	)		47,468		1,407			(528	)		48,347
Gross property additions		4,058		50		—			4,108		14			—			4,122
2007
Operating revenues	$	14,851	$	972	$	(683	)	$	15,140	$	380		$	(167	)	$	15,353
Depreciation and amortization		1,141		74		—			1,215		30			—			1,245
Interest income		31		1		—			32		14			(1	)		45
Interest expense		685		79		—			764		122			—			886
Income taxes		866		84		—			950		(115	)		—			835
Segment net income (loss)*		1,582		132		—			1,714		22			(2	)		1,734
Total assets		41,812		2,769		(122	)		44,459		1,767			(437	)		45,789
Gross property additions		3,465		184		(4	)		3,645		13			—			3,658

* After dividends on preferred and preference stock of subsidiaries

Products and Services

Electric Utilities’ Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2009	$	13,307	$	1,802	$	533	$	15,642
2008		14,055		2,400		545		17,000
2007		12,639		1,988		513		15,140

II-93

NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2009 and 2008 are as follows:

					Consolidated
					Net Income After
					Dividends on			Per Common Share
					Preferred and								Trading
	Operating		Operating		Preference Stock			Basic					Price Range
Quarter Ended	Revenues		Income		of Subsidiaries			Earnings			Dividends		High		Low
			(in millions)
March 2009	$	3,666	$	490	$	126	*	$	0.16	*	$	0.4200	$	37.62	$	26.48
June 2009		3,885		886		478			0.61			0.4375		32.05		27.19
September 2009		4,682		1,415		790			0.99			0.4375		32.67		30.27
December 2009		3,510		477		249			0.31			0.4375		34.47		30.89
March 2008	$	3,683	$	708	$	359		$	0.47		$	0.4025	$	40.60	$	33.71
June 2008		4,215		924		417			0.54			0.4200		37.81		34.28
September 2008		5,427		1,405		780			1.01			0.4200		40.00		34.46
December 2008		3,802		469		186			0.24			0.4200		38.18		29.82

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

* Southern Company’s MC Asset Recovery litigation settlement reduced earnings by $202 million, or 25 cents per share, during the first quarter of 2009.

II-94

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2005 through 2009
Southern Company and Subsidiary Companies 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in millions)	$	15,743	$	17,127	$	15,353	$	14,356	$	13,554
Total Assets (in millions)	$	52,046	$	48,347	$	45,789	$	42,858	$	39,877
Gross Property Additions (in millions)	$	4,913	$	4,122	$	3,658	$	3,072	$	2,476
Return on Average Common Equity (percent)		11.67		13.57		14.60		14.26		15.17
Cash Dividends Paid Per Share of Common Stock	$	1.7325	$	1.6625	$	1.595	$	1.535	$	1.475
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries (in millions)	$	1,643	$	1,742	$	1,734	$	1,573	$	1,591
Earnings Per Share —
Basic	$	2.07	$	2.26	$	2.29	$	2.12	$	2.14
Diluted		2.06		2.25		2.28		2.10		2.13
Capitalization (in millions):
Common stock equity	$	14,878	$	13,276	$	12,385	$	11,371	$	10,689
Preferred and preference stock of subsidiaries		707		707		707		246		98
Redeemable preferred stock of subsidiaries		375		375		373		498		498
Long-term debt		18,131		16,816		14,143		12,503		12,846
Total (excluding amounts due within one year)	$	34,091	$	31,174	$	27,608	$	24,618	$	24,131
Capitalization Ratios (percent):
Common stock equity		43.6		42.6		44.9		46.2		44.3
Preferred and preference stock of subsidiaries		2.1		2.3		2.6		1.0		0.4
Redeemable preferred stock of subsidiaries		1.1		1.2		1.3		2.0		2.1
Long-term debt		53.2		53.9		51.2		50.8		53.2
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	$	18.15	$	17.08	$	16.23	$	15.24	$	14.42
Market price per share:
High	$	37.62	$	40.60	$	39.35	$	37.40	$	36.47
Low		26.48		29.82		33.16		30.48		31.14
Close (year-end)		33.32		37.00		38.75		36.86		34.53
Market-to-book ratio (year-end) (percent)		183.6		216.6		238.8		241.9		239.5
Price-earnings ratio (year-end) (times)		16.1		16.4		16.9		17.4		16.1
Dividends paid (in millions)	$	1,369	$	1,279	$	1,204	$	1,140	$	1,098
Dividend yield (year-end) (percent)		5.2		4.5		4.1		4.2		4.3
Dividend payout ratio (percent)		83.3		73.5		69.5		72.4		69.0
Shares outstanding (in thousands):
Average		794,795		771,039		756,350		743,146		743,927
Year-end		819,647		777,192		763,104		746,270		741,448
Stockholders of record (year-end)		92,799		97,324		102,903		110,259		118,285
Traditional Operating Company Customers (year-end) (in thousands):
Residential		3,798		3,785		3,756		3,706		3,642
Commercial		580		594		600		596		586
Industrial		15		15		15		15		15
Other		9		8		6		5		5
Total		4,402		4,402		4,377		4,322		4,248
Employees (year-end)		26,112		27,276		26,472		26,091		25,554

II-95

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2005 through 2009
Southern Company and Subsidiary Companies 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in millions):
Residential	$	5,481	$	5,476	$	5,045	$	4,716	$	4,376
Commercial		4,901		5,018		4,467		4,117		3,904
Industrial		2,806		3,445		3,020		2,866		2,785
Other		119		116		107		102		100
Total retail		13,307		14,055		12,639		11,801		11,165
Wholesale		1,802		2,400		1,988		1,822		1,667
Total revenues from sales of electricity		15,109		16,455		14,627		13,623		12,832
Other revenues		634		672		726		733		722
Total	$	15,743	$	17,127	$	15,353	$	14,356	$	13,554
Kilowatt-Hour Sales (in millions):
Residential		51,690		52,262		53,326		52,383		51,082
Commercial		53,526		54,427		54,665		52,987		51,857
Industrial		46,422		52,636		54,662		55,044		55,141
Other		953		934		962		920		996
Total retail		152,591		160,259		163,615		161,334		159,076
Wholesale sales		33,503		39,368		40,745		38,460		37,072
Total		186,094		199,627		204,360		199,794		196,148
Average Revenue Per Kilowatt-Hour (cents):
Residential		10.60		10.48		9.46		9.00		8.57
Commercial		9.16		9.22		8.17		7.77		7.53
Industrial		6.04		6.54		5.52		5.21		5.05
Total retail		8.72		8.77		7.72		7.31		7.02
Wholesale		5.38		6.10		4.88		4.74		4.50
Total sales		8.12		8.24		7.16		6.82		6.54
Average Annual Kilowatt-Hour
Use Per Residential Customer		13,607		13,844		14,263		14,235		14,084
Average Annual Revenue
Per Residential Customer	$	1,443	$	1,451	$	1,349	$	1,282	$	1,207
Plant Nameplate Capacity
Ratings (year-end) (megawatts)		42,932		42,607		41,948		41,785		40,509
Maximum Peak-Hour Demand (megawatts):
Winter		33,519		32,604		31,189		30,958		30,384
Summer		34,471		37,166		38,777		35,890		35,050
System Reserve Margin (at peak) (percent)		26.4		15.3		11.2		17.1		14.4
Annual Load Factor (percent)		60.6		58.7		57.6		60.8		60.2
Plant Availability (percent):
Fossil-steam		91.3		90.5		90.5		89.3		89.0
Nuclear		90.1		91.3		90.8		91.5		90.5
Source of Energy Supply (percent):
Coal		54.7		64.0		67.1		67.2		67.4
Nuclear		14.9		14.0		13.4		14.0		14.0
Hydro		3.9		1.4		0.9		1.9		3.1
Oil and gas		22.5		15.4		15.0		12.9		10.9
Purchased power		4.0		5.2		3.6		4.0		4.6
Total		100.0		100.0		100.0		100.0		100.0

II-96

ALABAMA POWER COMPANY

FINANCIAL SECTION

II-97

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2009 Annual Report

The management of Alabama Power Company (the “Company”) 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 the 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. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

/s/ Charles D. McCrary

Charles D. McCrary
President and Chief Executive Officer

/s/ Art P. Beattie

Art P. Beattie
Executive Vice President, Chief Financial Officer, and Treasurer

February 25, 2010

II-98

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, 2009 and 2008, 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, 2009. 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 financial statements (pages II-123 to II-166) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Birmingham, Alabama
February 25, 2010

II-99

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2009 Annual Report

OVERVIEW

Business Activities

Alabama Power Company (the Company) operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition 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 constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge the Company for the foreseeable future.

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 after dividends on preferred and preference stock. 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 and nuclear 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. The fossil/hydro 2009 Peak Season EFOR of 1.50% was better than the target. The nuclear 2009 Peak Season EFOR of 0.14% was better than the target. 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 performance for 2009 was better than the target for these reliability measures.

Net income after dividends on preferred and preference stock is the primary measure of the Company’s financial performance. The Company’s 2009 results compared with its targets for some of these key indicators are reflected in the following chart.

	2009	2009
	Target	Actual
Key Performance Indicator	Performance	Performance
	Top quartile in
Customer Satisfaction	customer surveys	Top quartile
Peak Season EFOR — fossil/hydro	2.75% or less	1.50%
Peak Season EFOR — nuclear	2.75% or less	0.14%
Net Income	$666 million	$670 million

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2009 reflects the continued management emphasis, as well as the commitment shown by employees, in achieving or exceeding these key performance expectations.

Earnings

The Company’s financial performance remained strong in 2009 despite the challenges of a recessionary economy. The Company’s net income after dividends on preferred and preference stock of $670 million in 2009 increased $54 million (8.7%) over the prior year. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures effective in January 2009, a decrease in other operations and maintenance expenses, and an increase in allowance for funds used during construction (AFUDC) equity. The increase was partially offset by an overall decline in base rate revenues attributable to a decline in kilowatt-hour (KWH) sales, resulting from a recessionary economy and unfavorable weather conditions.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

The Company’s net income after dividends on preferred and preference stock of $616 million in 2008 increased $36 million (6.3%) over the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under the Rate Stabilization and Equalization Plan (Rate RSE) and the Rate Certificated New Plant (Rate CNP) for environmental costs that took effect January 1, 2008, partially offset by higher non-fuel operating expenses and depreciation.

The Company’s 2007 net income after dividends on preferred and preference stock was $580 million, representing a $62 million (11.9%) increase from the prior year. This improvement was primarily due to an increase in retail base rate revenues resulting from an increase in rates under Rate RSE and Rate CNP for environmental costs that took effect January 1, 2007 as well as favorable weather conditions, partially offset by higher non-fuel operating expenses and increased interest expense.

RESULTS OF OPERATIONS

A condensed income statement for the Company follows:

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008		2007
	(in millions)
Operating revenues	$	5,529		$	(548	)	$	717	$	345
Fuel		1,824			(360	)		422		90
Purchased power		307			(232	)		99		12
Other operations and maintenance		1,211			(48	)		73		89
Depreciation and amortization		545			25			49		21
Taxes other than income taxes		322			16			20		28
Total operating expenses		4,209			(599	)		663		240
Operating income		1,320			51			54		105
Total other income and (expense)		(227	)		19			2		(11	)
Income taxes		384			16			16		21
Net income		709			54			40		73
Dividends on preferred and preference stock		39			—			4		11
Net income after dividends on preferred and preference stock	$	670		$	54		$	36	$	62

Operating Revenues

Operating revenues for 2009 were $5.5 billion, reflecting a $548 million decrease from 2008. The following table summarizes the principal factors that have affected operating revenues for the past three years:

	Amount
	2009			2008			2007
	(in millions)
Retail — prior year	$	4,862		$	4,407		$	3,996
Estimated change in —
Rates and pricing		174			246			216
Sales growth (decline)		(109	)		26			(5	)
Weather		(12	)		(70	)		38
Fuel and other cost recovery		(418	)		253			162
Retail — current year		4,497			4,862			4,407
Wholesale revenues —
Non-affiliates		620			712			627
Affiliates		237			309			144
Total wholesale revenues		857			1,021			771
Other operating revenues		175			194			182
Total operating revenues	$	5,529		$	6,077		$	5,360
Percent change		(9	)%		13	%		7	%

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Retail revenues in 2009 were $4.5 billion. These revenues decreased $365 million (7.5%) in 2009 and increased $455 million (10.3%) and $411 million (10.3%) in 2008 and 2007, respectively. The decrease in 2009 was due to decreased fuel revenue and a decline in KWH sales, partially offset by the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures. The increases in 2008 and 2007 were primarily due to increases in fuel revenue and base rate increases of 5.6% and 5.3%, respectively. See FUTURE EARNINGS POTENTIAL — “PSC Matters” herein and Note 3 to the financial statements under “Retail Regulatory Matters” for additional information. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

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 — Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.

Wholesale revenues from sales to non-affiliated utilities were as follows:

	2009		2008		2007
	(in millions)
Unit power sales —
Capacity	$	158	$	160	$	151
Energy		207		238		192
Total		365		398		343
Other power sales —
Capacity and other		133		134		128
Energy		122		180		156
Total		255		314		284
Total non-affiliated	$	620	$	712	$	627

Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.

Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to Florida utilities and sales to wholesale customers within the Company’s service territory. Capacity revenues under unit power sales contracts reflect the recovery of fixed costs and a return on investment, and under these contracts, energy is generally sold at variable cost. Fluctuations in the prices of oil and natural gas, which are the primary fuel sources for unit power sales customers, influence changes in these energy sales. However, because energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The amounts of long-term unit power sales capacity revenues are scheduled to cease with the termination of the unit power sales contract in May 2010. In June 2010, the capacity subject to the unit power sales contracts will be utilized for retail service. As shown in the table above, unit power sales capacity revenues have ranged from $151 million to $160 million over the last three years. Short-term opportunity energy sales are also included in wholesale energy sales 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. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Retail Rate Adjustments” herein and Note 3 to the financial statements under “Retail Regulatory Matters — Rate RSE” for additional information.

Wholesale revenues from sales to affiliated companies within the Southern Company system 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 2009, wholesale revenues from sales to affiliates decreased $71.5 million primarily due to a 37.6% decrease in price, partially offset by a 23.2% increase in KWH sales to affiliates as a result of greater availability of the Company’s generating resources because of a decrease in customer demand within the Company’s service territory. In 2008, wholesale revenues from sales to affiliates increased $164.4 million primarily due to a 62.2% increase in KWH sales to affiliates as a result of greater availability of the Company’s generating resources because of a decrease in customer demand within the Company’s service territory. In 2007, wholesale revenues from sales to affiliates decreased $71.9 million primarily due to a 37.0% decrease in KWH sales to affiliates as a result of lower availability of the Company’s generating resources because of an increase in customer demand within the Company’s service territory.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

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 clauses.

Other operating revenues in 2009 decreased $19.6 million (10.1%) from 2008 primarily due to a $42.5 million decrease in revenues from gas-fueled co-generation steam facilities as a result of lower gas prices. This decrease was partially offset by an increase of $10.0 million in customer charges related to late fees. In 2008, other operating revenues increased $12.4 million (6.8%) from 2007 primarily due to an $11.7 million increase in revenues from gas-fueled co-generation steam facilities. In 2007, other operating revenues increased $13.5 million (8.0%) from 2006 primarily due to a $4.0 million increase in revenues from electric property associated with pole attachment and building rentals, a $2.6 million increase in transmission revenues, and a $2.5 million increase in revenues from gas-fueled co-generation steam facilities. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings for any year reported.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2009 and the percent change by year were as follows:

	KWHs		Percent Change
	2009		2009			2008			2007
	(in billions)
Residential		18.1		(1.7	)%		(2.6	)%		1.3	%
Commercial		14.2		(2.5	)		(1.4	)		2.8
Industrial		18.5		(15.9	)		(3.2	)		(1.6	)
Other		0.2		8.1			0.2			0.7
Total retail		51.0		(7.6	)		(2.5	)		0.5
Wholesale —
Non-affiliates		14.3		(5.8	)		(3.6	)		(1.3	)
Affiliates		6.5		23.2			62.2			(37.0	)
Total wholesale		20.8		1.6			7.6			(10.0	)
Total energy sales		71.8		(5.1	)		0.0			(2.4	)

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2009 were 7.6% less than in 2008. Energy sales were down in 2009 across major classes of customers. Residential and commercial sales decreased 1.7% and 2.5%, respectively, due primarily to unfavorable weather and decreased customer demand in 2009 as compared to 2008. Industrial sales decreased 15.9% during the year as a result of decreased customer demand in all sectors, most significantly in the chemical and primary metals sectors, due to a recessionary economy.

Retail energy sales in 2008 were 2.5% less than in 2007. Energy sales were down in 2008 across major classes of customers. Residential and commercial sales decreased 2.6% and 1.4%, respectively, due primarily to unfavorable weather in 2008 compared to 2007. Industrial sales decreased 3.2% during the year primarily as a result of decreased customer demand in the chemical and pipeline, and textiles and food sectors, as a result of a slowing economy that worsened during the fourth quarter of 2008.

Retail energy sales in 2007 were 0.5% higher than in 2006. Energy sales in the residential and commercial sectors led the growth with a 1.3% and a 2.8% increase, respectively, due primarily to weather-driven increased demand. Industrial sales decreased 1.6% during the year primarily as a result of decreased sales demand in textiles and food, primary metals, and chemical sectors.

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 generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Details of the Company’s electricity generated and purchased were as follows:

	2009		2008		2007
Total generation(billions of KWHs)		68.8		70.0		69.8
Total purchased power(billions of KWHs)		6.3		9.2		9.6
Sources of generation(percent) —
Coal		58		66		69
Nuclear		20		20		19
Gas		13		11		10
Hydro		9		3		2
Cost of fuel, generated(cents per net KWH) —
Coal		3.02		2.94		2.14
Nuclear		0.56		0.50		0.50
Gas		5.24		8.30		7.43
Average cost of fuel, generated(cents per net KWH)*		2.79		3.00		2.36
Average cost of purchased power(cents per net KWH)		6.05		7.44		6.07

* Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

Fuel and purchased power expenses were $2.1 billion in 2009, a decrease of $592.1 million (21.8%) below the prior year costs. This decrease was the result of a $367.3 million decrease related to the volume of KWHs generated and purchased and a $224.8 million decrease in the cost of fuel resulting from lower natural gas prices and an increase in hydro generation.

Fuel and purchased power expenses were $2.7 billion in 2008, an increase of $521.5 million (23.7%) above the prior year costs. This increase was the result of a $560.8 million increase in the cost of fuel, offset by a $39.3 million decrease related to the volume of KWHs generated and purchased.

Fuel and purchased power expenses were $2.2 billion in 2007, an increase of $101.9 million (4.9%) above the prior year costs. This increase was the result of a $70.3 million increase in the cost of fuel and a $31.6 million increase related to the volume of KWHs generated and purchased.

Purchased power consists of purchases from affiliates in the Southern Company system and non-affiliated companies. Purchased power transactions among the Company, its affiliates, and non-affiliates will vary from period to period depending on demand and the availability and variable production cost of generating resources at each company. In 2009, purchased power from non-affiliates decreased $91.1 million (50.9%) due to a 34.9% decrease in the amount of energy purchased and a 24.6% decrease in the average cost per KWH. In 2009, purchased power from affiliates decreased $140.5 million (39.1%) due to a 31.4% decrease in the amount of energy purchased. In 2008, the average cost of purchased power from non-affiliates increased $81.9 million (84.5%) due to a 67.9% increase in the amount of energy purchased. In 2007, purchased power from non-affiliates decreased $27.1 million (21.8%) due to a 22.6% decrease in the amount of energy purchased.

Coal prices continued to be influenced by worldwide demand from developing countries, as well as increased mining and fuel transportation costs. While coal prices reached unprecedented high levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices did not fully offset the higher priced coal already in inventory and under long-term contract. Demand for natural gas in the United States also was affected by the recessionary economy leading to significantly lower natural gas prices. During 2009, uranium prices continued to moderate from the highs set during 2007. Worldwide production levels increased in 2009; however, secondary supplies and inventories were still required to meet worldwide reactor demand.

Fuel and purchased power expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s energy cost recovery rate (Rate ECR). The Company, along with the Alabama Public Service Commission (PSC), continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Other Operations and Maintenance Expenses

In 2009, other operations and maintenance expenses decreased $47.6 million (3.8%) primarily due to an $18.1 million decrease in steam production expense related to fewer scheduled outages, a $12.9 million decrease in administrative and general expense related to reductions in employee medical and other benefit-related expenses and in the injuries and damages reserve, a $5.5 million decrease in customer accounts expense, and a $4.7 million decrease in customer service and information expense.

In 2008, other operations and maintenance expenses increased $72.7 million (6.1%) primarily due to a $27.4 million increase in steam production expense related to environmental mandates (which were offset by revenues associated with Rate CNP environmental) and scheduled outage costs, a $22.9 million increase in nuclear production expense related to operations and scheduled outage costs, and a $19.9 million increase in transmission and distribution expense related to overhead line clearing costs.

In 2007, other operations and maintenance expenses increased $89.3 million (8.1%) primarily due to a $28.5 million increase in steam production expense related to environmental mandates and scheduled outage costs, a $19.6 million increase in transmission and distribution expense related to overhead line clearing costs, a $19.0 million increase in administrative and general expenses related to an increase in the expenses for the injuries and damages reserve, outside services, and employee benefits, an $8.1 million increase in nuclear production expense related to scheduled outage cost, and a $4.7 million increase in customer accounts expense associated with customer service expenses.

Depreciation and Amortization

Depreciation and amortization increased $24.5 million (4.7%) in 2009, $48.9 million (10.4%) in 2008, and $20.5 million (4.5%) in 2007, primarily due to additions to property, plant, and equipment related to environmental mandates (which were offset by revenues associated with Rate CNP environmental) and transmission and distribution projects. See Note 3 to financial statements under “Retail Regulatory Matters — Rate CNP” for additional information.

On June 25, 2009, the Company submitted an offer of settlement and stipulation to the FERC relating to the 2008 depreciation study that was filed in October 2008. The settlement offer withdraws the requests for authorization to use updated depreciation rates. In lieu of the new rates, the Company is using those depreciation rates employed prior and up to January 1, 2009 that were previously approved by the FERC. On September 30, 2009, the FERC issued an order approving the settlement offer. See Note 1 to financial statements under “Depreciation and Amortization” for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $15.8 million (5.1%) in 2009, $19.9 million (7.0%) in 2008, and $28.4 million (11.0%) in 2007, primarily due to increases in the bases of state and municipal public utility license taxes.

Allowance for Funds Used During Construction Equity

AFUDC equity increased $33.7 million (73.9%) in 2009, $10.1 million (28.5%) in 2008, and $17.2 million (94.1%) in 2007, primarily due to increases in construction work in progress related to environmental mandates at generating facilities, as well as transmission, distribution, and general plant projects compared to the prior years. See Note 1 to financial statements under “Allowance for Funds Used During Construction” for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized, increased $19.6 million (7.0%) in 2009 primarily due to the issuance of long-term debt, partially offset by additional capitalized interest, as a result of increases in construction work in progress. Interest expense, net of amounts capitalized, increased $5.2 million (1.9%) in 2008 which was not material when compared to the prior year. Interest expense, net of amounts capitalized, increased $21.5 million (8.5%) in 2007 primarily due to higher interest rates on new issuance of long-term debt and higher interest rates on the Company’s outstanding variable rate securities.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Income Taxes

Income taxes increased $16.2 million (4.4%) in 2009, primarily due to higher pre-tax income, prior year tax return actualization, and an increase in expense related to normal tax contingencies, partially offset by the tax benefits associated with an increase in AFUDC equity and an increase in the federal production activities deduction.

Income taxes increased $16.6 million (4.7%) in 2008, primarily due to higher pre-tax income partially offset by the tax benefit associated with an increase in AFUDC equity and a decrease in expense related to normal tax contingencies.

Income taxes increased $20.9 million (6.3%) in 2007, primarily due to higher pre-tax income partially offset by the tax benefit associated with an increase in AFUDC equity and an increase in the federal production activities deduction.

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial. See Note 3 to financial statements under “Retail Regulatory Matters — Rate RSE” for additional information.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition 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 wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated 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 regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining 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 or decline in the Company’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly on industrial and commercial customers. The timing and extent of the economic recovery will impact future earnings.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.

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 the Company, 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. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to each of the

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

traditional operating companies. After the Company was dismissed from the original action, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama. In the lawsuit against the Company, the EPA alleges that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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; the Endangered Species Act; and related federal and state regulations. 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 2009, the Company had invested approximately $2.8 billion in capital projects to comply with these requirements, with annual totals of $526 million, $617 million, and $469 million for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $136 million, $85 million, and $99 million for 2010, 2011, and 2012, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, 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 2009, the Company had spent approximately $2.5 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment under the current standard. In March 2008, however, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to finalize the revised standard in August 2010 and require state implementation plans for any nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory.

During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the Company’s service area. State plans for addressing the nonattainment designations for this standard could require further reductions in SO₂ and NO_x emissions from power plants. In September 2006, the EPA published a final rule which increased the stringency of the 24-hour average fine particulate matter air quality standard. The Birmingham, Alabama area has been designated as nonattainment for the 24-hour standard, and a state implementation plan for this nonattainment area is due in December 2012.

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On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard for SO₂. The EPA is expected to finalize the revised SO₂ standard in June 2010.

Twenty-eight eastern states, including the State of Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The State of Alabama has completed its plan to implement CAIR, and emissions reductions are being accomplished by the installation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in July 2010.

The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring 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) to certain sources built between 1962 and 1977, and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural conditions goal by 2018 and for each ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. The State of Alabama has completed its implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress.

The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants, including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and trade program for the reduction of mercury emissions from coal-fired power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.

The impacts of the eight-hour ozone standards, the fine particulate matter nonattainment designations, and future revisions to CAIR, the SO₂ standard, the Clean Air Visibility Rule, and MACT rule for the electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO₂ and NO_x emissions controls and plans to install additional controls within the next several years to ensure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is now in the process of revising the regulations. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on further rulemaking by the EPA and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

On December 28, 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions by 2013. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, and, therefore, cannot be determined at this time.

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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 releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters — Environmental Remediation” for additional information.

Coal Combustion Byproducts

The EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA has collected information from the electric utility industry on surface impoundment safety, and conducted on-site inspections at one of the Company’s facilities as part of its evaluation. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010. The impact of these additional regulations on the Company will depend on the specific provisions of the final rule and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the Company’s management, beneficial use, and disposal of such byproducts and could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

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Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 47 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 43 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.

FERC Matters

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 expired in July and August 2007. Since the FERC did not act on the Company’s new license applications prior to the expiration of the existing licenses, the FERC is required by law to issue annual licenses to the Company, under the terms and conditions of the existing license, until action is taken on the new license applications. The FERC issued an annual license for the Coosa developments in August 2007 and issued an annual license for the Warrior developments in September 2007. These annual licenses were automatically renewed in 2009 without further action by the FERC to allow the Company to continue operation of the projects under the terms of the previous license while the FERC completes review of the applications for new licenses.

In 2006, the Company initiated the process of developing an application to relicense the Martin hydroelectric project located on the Tallapoosa River. The current Martin license will expire in 2013 and the application for a new license is expected to be filed with the FERC in 2011.

In 2010, the Company will initiate the process of developing an application to relicense the Holt hydroelectric project located on the Warrior River. The current Holt license will expire on August 31, 2015, and the application for a new license is expected to be filed prior to that time.

Upon or after the expiration of each license, the U.S. 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 timing and final outcome of the Company’s relicense applications cannot now be determined.

PSC Matters

Retail Rate Adjustments

Rate RSE

Rate RSE adjustments are 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% per year and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity is projected to be between 13.0% and 14.5%. 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.

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Alabama Power Company 2009 Annual Report

In October 2008, the Alabama PSC approved a corrective rate package, effective January 2009, that primarily provides for adjustments associated with customer charges to certain existing rate structures. The Company agreed to a moratorium on any increase in rates in 2009 under the Rate RSE.

On December 1, 2009, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2010. The Rate RSE increase for 2010 is 3.24%, or $152 million annually, and was effective in January 2010. The revenue adjustment under the Rate RSE is largely attributable to the costs associated with fossil capacity which is currently dedicated to certain long-term wholesale contracts that expire during 2010. Retail cost of service for 2010 reflects the cost for that portion of the year in which this capacity is no longer committed to wholesale. The termination of these long-term wholesale contracts will result in a significant decrease in unit power sales capacity revenues. In an Alabama PSC order dated January 5, 2010, the Alabama PSC acknowledged that a full calendar year of costs for such capacity would be reflected in the Rate RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the maximum increase for 2011 cannot exceed 4.76%.

Rate CNP

The Company’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated power purchase agreements (PPAs) under a Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2007, 2008, or 2009. Effective April 2010, Rate CNP will be reduced approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1.

Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 0.6% in January 2007 and 2.4% in January 2008 due to environmental costs. In October 2008, the Company agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2009, the Company made its Rate CNP environmental submission of projected data for calendar year 2010, resulting in an increase to retail rates of approximately 4.3%, or an additional $195 million annually, based upon projected billings. Under the terms of the rate mechanism, this adjustment became effective in January 2010. The Rate CNP environmental adjustment is primarily attributable to scrubbers being placed in service during 2010 at four of the Company’s generating units. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate CNP” for further information.

Fuel Cost Recovery

The Company has established fuel cost recovery rates under Rate ECR approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the over recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.

In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per KWH effective with billings beginning July 2007. In October 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH effective with billings beginning October 2008.

On June 2, 2009, the Alabama PSC approved a decrease in the Company’s Rate ECR factor to 3.733 cents per KWH for billings beginning June 9, 2009. On December 1, 2009, the Alabama PSC approved a decrease in the Company’s Rate ECR factor to 2.731 cents per KWH for billings beginning January 2010 through December 2011. The Alabama PSC further approved an additional reduction in the Rate ECR factor of 0.328 cents per KWH for the billing months of January 2010 through December 2010 resulting in a Rate ECR factor of 2.403 cents per KWH for such 12-month period. For billing months beginning January 2012, the Rate ECR factor shall be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, the approved decreases in the Rate ECR factor will have no significant effect on the Company’s net income, but will decrease operating cash flows related to fuel cost recovery in 2010 when compared to 2009.

As of December 31, 2009, the Company had an over recovered fuel balance of approximately $199.6 million, of which approximately $22.1 million is included in deferred over recovered regulatory clause revenues in the balance sheets. As of December 31, 2008, the

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Company had an under recovered fuel balance of approximately $305.8 million, of which approximately $180.9 million is included in deferred under recovered regulatory clause revenues in the balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs or recovery of under recovered fuel costs. See Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for further information.

Natural Disaster Reserve

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly natural disaster reserve (NDR) charge to customers consisting of two components. 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 second component of the NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, 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. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant.

In addition to the monthly NDR charge, the Company accrued $39.6 million of discretionary reserve in 2009 resulting in an accumulated balance of approximately $75 million in the reserve for future storms as of December 31, 2009. This reserve is included in other regulatory liabilities, deferred in the balance sheets. Effective February 2010, billings will be reduced to $0.37 per month per non-residential customer account and $0.15 per month per residential customer account, consistent with the Alabama PSC order to maintain the target NDR balance. The Company has fully recovered its deferred storm costs; therefore, rates do not include the second component of the NDR charge.

As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, any change in revenue and expense will not have an effect on net income but will decrease operating cash flows related to the NDR charge in 2010 when compared to 2009.

The net effect of the changes in 2010 in the Rate ECR factor, Rate RSE, Rate CNP, and NDR will result in an overall annual reduction in the Company’s retail customers’ billings of approximately $433 million.

Steam Service

On February 5, 2009, the Alabama PSC granted a Certificate of Abandonment of Steam Service in the downtown area of the City of Birmingham. The order allows the Company to discontinue steam service by the earlier of three years from May 14, 2008 or when it has no remaining steam service customers. Currently, the Company has contractual obligations to provide steam service until 2013. Impacts related to the abandonment of steam service are recognized in operating income and are not material to the earnings of the Company.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of the Company. The Company’s cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA was approximately $104 million. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of the Company.

On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $65 million is available to the Company, under the ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. The Company continues to assess the other financial implications of the ARRA.

The U.S. House of Representatives and the U.S. Senate have passed separate bills related to healthcare reform. Both bills include a provision that would make Medicare Part D subsidy reimbursements taxable. If enacted into law, this provision could have a

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Alabama Power Company 2009 Annual Report

significant negative impact on the Company’s net income. See Note 2 to the financial statements under “Other Postretirement Benefits” for additional information.

The ultimate impact of these matters cannot be determined at this time.

Income Tax Matters

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Other Matters

In accordance with accounting standards related to employers’ accounting for pensions, the Company recorded non-cash pre-tax pension income of approximately $24 million, $26 million, and $17 million in 2009, 2008, and 2007, respectively. Postretirement benefit costs for the Company were $19 million, $23 million, and $27 million in 2009, 2008, and 2007, respectively. 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. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require 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 the accounting standards 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,

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Alabama Power Company 2009 Annual Report

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 financial statements 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 results of operations.

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, in accordance with generally accepted accounting principles (GAAP), records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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, coal combustion byproducts, including coal ash, 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) or Alabama Department of Revenue interpretations of existing regulations.

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

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

• Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, the Alabama Department of Revenue, the FERC, or the EPA.

Unbilled Revenues

Revenues related to the retail 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.

Pension and Other Postretirement Benefits

The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

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Alabama Power Company 2009 Annual Report

Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that considers external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption would result in a $6 million or less change in total benefit expense and a $68 million or less change in projected obligations.

New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted this new guidance effective January 1, 2010, with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2009. Throughout the turmoil in the financial markets, the Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and the Company has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees for the Company average less than¹/4 of 1% per year. See “Sources of Capital” and “Financing Activities” herein for additional information.

The Company’s investments in pension and nuclear decommissioning trust funds remained stable in value as of December 31, 2009. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables, including future trust fund performance, and cannot be determined at this time. The Company’s funding obligations for the nuclear decommissioning trust are based on the site study, and the next study is expected to be conducted in 2013.

Net cash provided from operating activities in 2009 totaled $1.6 billion, an increase of $424 million as compared to 2008. The increase was primarily due to an increase in net income, as previously discussed, a decrease in receivables, and an increase in other current liabilities attributable to collections on regulatory clauses. Net cash provided from operating activities in 2008 totaled $1.2 billion, an increase of $30 million as compared to 2007. The increase included additional use of funds for fossil fuel inventory and payment of operating expenses along with a higher receivables balance as compared to 2007. This use of funds was offset by an increase in cash from net income as previously discussed and higher depreciation expense along with a decrease in the payments for federal taxes as compared to 2007. Net cash provided from operating activities in 2007 totaled $1.2 billion, an increase of $194 million as compared to 2006. The increase was primarily due to an increase in net income resulting from price increases, an increase in deferred taxes, and the timing of payments related to operating expenses.

Net cash used for investing activities totaled $1.2 billion, $1.6 billion, and $1.3 billion for 2009, 2008, and 2007, respectively, primarily due to gross property additions to utility plant of $1.2 billion, $1.5 billion and $1.2 billion for 2009, 2008, and 2007, respectively. These additions were primarily related to environmental mandates, construction of transmission and distribution facilities, replacement of steam generation equipment, and purchases of nuclear fuel.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Net cash used for financing activities totaled $35 million in 2009 primarily due to redemptions of debt securities and dividends paid in excess of debt issuances and cash raised from common stock sales. In 2008 and 2007, net cash provided from financing activities totaled $375 million and $162 million, respectively, primarily due to long-term debt issuances and cash raised from common stock sales in excess of redemptions of securities and dividends paid. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and securities redeemed.

Significant balance sheet changes for 2009 include increases of $340 million in cash primarily from collections on regulatory clauses. These cash collections correspondingly decreased current and deferred under recovered regulatory clause revenues by $297 million and increased current and deferred over recovered regulatory clause revenues by $204 million. Other changes include increases of $939 million in gross plant related to environmental mandates and transmission and distribution projects and $478 million in long-term debt. In 2008, significant balance sheet changes included an increase of $966 million in gross plant and an increase of $855 million in long-term debt, primarily due to an increase in environmental-related equipment. Other significant balance sheet changes in 2008 were a result of a decline in the market value of the Company’s pension trust and nuclear decommissioning trust funds, impacting the Company’s other regulatory assets and liabilities. In 2007, significant balance sheet changes included an increase of $671 million in gross plant and an increase of $602 million in long-term debt, primarily due to an increase in environmental-related equipment.

The Company’s ratio of common equity to total capitalization, including short-term debt, was 43.3% in 2009, 42.5% in 2008, and 42.5% in 2007. See Note 6 to the financial statements for additional information.

The Company has maintained investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock. See SELECTED FINANCIAL AND OPERATING DATA for additional information regarding the Company’s securities ratings.

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, unsecured debt, common stock, preferred stock, and preference stock. However, the type and timing of any financings will depend on market conditions, regulatory approval, and other factors.

Security issuances are subject to regulatory approval by the Alabama PSC. 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. The amounts of securities authorized by the Alabama PSC 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 sometimes exceed current assets because of the Company’s debt due within one year and the periodic use of short-term debt as a funding source primarily 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 December 31, 2009, the Company had approximately $368 million of cash and cash equivalents and $1.3 billion 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 a commercial paper program, to meet liquidity needs.

The Company maintains committed lines of credit in the amount of $1.3 billion, of which $481 million will expire at various times during 2010. $372 million of the credit facilities expiring in 2010 allow for the execution of term loans for an additional one-year period. $765 million of credit facilities expire in 2012. A portion of the unused credit with banks is allocated to provide liquidity support to the Company’s variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2009 was approximately $608 million. Subsequent to December 31, 2009, two remarketings of pollution control revenue bonds increased that amount to $744 million. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional 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 traditional operating company. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

The Company had no commercial paper outstanding as of December 31, 2009, and $25 million outstanding as of December 31, 2008.

Financing Activities

In March 2009, the Company issued $500 million of Series 2009A 6.00% Senior Notes due March 1, 2039. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program.

In June 2009, the Company incurred obligations related to the issuance of $53 million of the Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Barry Plant Project), First Series 2009. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Barry.

In July 2009, the Company issued 3,375,000 shares of common stock to Southern Company at $40 a share ($135 million aggregate purchase price). The proceeds were used for general corporate purposes.

In August 2009, the Company’s $250 million Series BB Floating Rate Senior Notes due August 25, 2009 matured.

In October 2009, the Company issued 1,687,500 shares of common stock to Southern Company at $40 a share ($67.5 million aggregate purchase price). The proceeds were used for general corporate purposes.

In December 2009, the Company incurred obligations related to the issuance of $25.5 million of the Industrial Development Board of the City of Mobile, Alabama Solid Waste Disposal Revenue Bonds (Alabama Power Barry Plant Project), Second Series 2009. The proceeds were used to fund certain solid waste disposal facilities at Plant Barry.

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.

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- and/or Baa3 or below. These contracts are primarily for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At December 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $5 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $324 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

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, where possible, 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)
Alabama Power Company 2009 Annual Report

To mitigate future exposure to changes in interest rates, the Company enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. The weighted average interest rate on $232 million of long-term variable interest rate exposure that has not been hedged at January 1, 2010 was 3.0%. 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 $2.3 million at January 1, 2010. For further information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

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 financial hedge contracts for natural gas purchases. The Company has implemented fuel hedging programs per the guidelines 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% 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% of the Company’s natural gas budget for that year.

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

	2009			2008
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(92	)	$	—
Contracts realized or settled		123			(44	)
Current period changes(a)		(75	)		(48	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(44	)	$	(92	)

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

The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2009 was an increase of $47.6 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and prices of natural gas. At December 31, 2009, the Company had a net hedge volume of 37.3 million mmBtu with a weighted average contract cost approximately $1.20 per mmBtu above market prices, and 44.5 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.12 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clause.

At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows:

Asset (Liability) Derivatives	2009			2008
	(in millions)
Regulatory hedges	$	(44	)	$	(92	)
Cash flow hedges		—			—
Not designated		—			—
Total fair value	$	(44	)	$	(92	)

Energy-related derivative contracts which are designated as regulatory hedges relate to the Company’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(44	)		(34	)		(10	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(44	)	$	(34	)	$	(10	)	$	—

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion on fair value measurement.

The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P 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 Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $1.0 billion for 2010, $1.0 billion for 2011, and $1.1 billion for 2012. Environmental expenditures included in these estimated amounts are $136 million, $85 million, and $99 million for 2010, 2011, and 2012, respectively. Also included over the next three years, the Company estimates spending $653 million on Plant Farley (including nuclear fuel), $882 million on distribution facilities, and $481 million on transmission additions. See Note 7 to the financial statements under “Construction Program” for additional details.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; 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 Nuclear Regulatory Commission requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.”

In addition to the funds required for the Company’s construction program, approximately $800 million will be required by the end of 2012 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.

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 an extended period will diminish internally funded capital for other purposes and may require the Company to seek capital from other sources. See Note 2 to the financial statements for additional information.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, 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, 7, and 11 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(d)		Total
	(in millions)
Long-term debt(a) —
Principal	$	100	$	700	$	250	$	5,136	$	—	$	6,186
Interest		311		603		530		4,846		—		6,290
Preferred and preference stock dividends(b)		39		79		79		—		—		197
Energy-related derivative obligations(c)		34		11		—		—		—		45
Operating leases		22		21		8		10		—		61
Unrecognized tax benefits and interest(d)		—		—		—		—		6		6
Purchase commitments(e) —
Capital(f)		912		1,919		—		—		—		2,831
Limestone(g)		11		30		32		54		—		127
Coal		1,420		1,589		923		975		—		4,907
Nuclear fuel		73		99		60		90		—		322
Natural gas(h)		413		451		254		148		—		1,266
Purchased power		39		60		67		337		—		503
Long-term service agreements(i)		23		48		50		135		—		256
Postretirement benefits trust(j)		11		22		—		—		—		33
Total	$	3,408	$	5,632	$	2,253	$	11,731	$	6	$	23,030

(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, 2010, 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)	Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(c)	For additional information, see Notes 1 and 11 to the financial statements.
(d)	The timing related to the realization of $6 million in unrecognized tax benefits and interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information.
(e)	The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2009, 2008, and 2007 were $1.21 billion, $1.26 billion, and $1.19 billion, respectively.
(f)	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 nuclear fuel. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program.
(g)	As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment.
(h)	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, 2009.
(i)	Long-term service agreements include price escalation based on inflation indices.
(j)	The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Therefore, no amounts related to the pension trust are included in the table. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (Continued)
Alabama Power Company 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales and retail rates, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, start and completion of construction projects, filings with state and federal regulatory authorities, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances, and also changes in 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 recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of the Company’s employee benefit plans and nuclear decommissioning trusts;

• advances in technology;

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

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

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

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

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STATEMENTS OF INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Alabama Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Revenues:
Retail revenues	$	4,497,081		$	4,862,281		$	4,406,956
Wholesale revenues, non-affiliates		619,859			711,903			627,047
Wholesale revenues, affiliates		236,995			308,482			144,089
Other revenues		174,639			194,265			181,901
Total operating revenues		5,528,574			6,076,931			5,359,993
Operating Expenses:
Fuel		1,823,784			2,184,310			1,762,418
Purchased power, non-affiliates		87,737			178,807			96,928
Purchased power, affiliates		218,654			359,202			341,461
Other operations and maintenance		1,211,245			1,258,888			1,186,235
Depreciation and amortization		544,923			520,449			471,536
Taxes other than income taxes		322,274			306,522			286,579
Total operating expenses		4,208,617			4,808,178			4,145,157
Operating Income		1,319,957			1,268,753			1,214,836
Other Income and (Expense):
Allowance for equity funds used during construction		79,175			45,519			35,425
Interest income		16,906			19,394			19,545
Interest expense, net of amounts capitalized		(298,495	)		(278,917	)		(273,737	)
Other income (expense), net		(24,564	)		(31,514	)		(29,144	)
Total other income and (expense)		(226,978	)		(245,518	)		(247,911	)
Earnings Before Income Taxes		1,092,979			1,023,235			966,925
Income taxes		383,980			367,813			351,198
Net Income		708,999			655,422			615,727
Dividends on Preferred and Preference Stock		39,463			39,463			36,145
Net Income After Dividends on Preferred and Preference Stock	$	669,536		$	615,959		$	579,582

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, 2009, 2008, and 2007
Alabama Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Activities:
Net income	$	708,999		$	655,422		$	615,727
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		636,788			599,767			548,959
Deferred income taxes		(65,907	)		126,538			21,269
Allowance for equity funds used during construction		(79,175	)		(45,519	)		(35,425	)
Pension, postretirement, and other employee benefits		(25,802	)		(26,530	)		(18,781	)
Stock based compensation expense		3,767			3,105			4,900
Tax benefit of stock options		166			685			1,118
Other, net		62,318			27,687			(13,648	)
Changes in certain current assets and liabilities —
-Receivables		310,203			(31,692	)		(5,798	)
-Fossil fuel stock		(76,602	)		(134,212	)		(33,840	)
-Materials and supplies		(21,989	)		(17,723	)		(32,543	)
-Other current assets		(16,253	)		(1,493	)		22,353
-Accounts payable		(18,767	)		(8,751	)		78,508
-Accrued taxes		24,415			36,957			(17,248	)
-Accrued compensation		(31,684	)		(4,722	)		4,194
-Other current liabilities		192,835			(198	)		10,098
Net cash provided from operating activities		1,603,312			1,179,321			1,149,843
Investing Activities:
Property additions		(1,233,580	)		(1,477,644	)		(1,157,186	)
Investment in restricted cash from pollution control bonds		(5,673	)		(96,326	)		(97,775	)
Distribution of restricted cash from pollution control bonds		49,041			35,979			78,043
Nuclear decommissioning trust fund purchases		(244,662	)		(300,503	)		(334,275	)
Nuclear decommissioning trust fund sales		243,796			299,636			333,409
Cost of removal net of salvage		(37,883	)		(41,744	)		(48,932	)
Other investing activities		165			(19,142	)		(26,621	)
Net cash used for investing activities		(1,228,796	)		(1,599,744	)		(1,253,337	)
Financing Activities:
Increase (decrease) in notes payable, net		(24,995	)		24,995			(119,670	)
Proceeds —
Common stock issued to parent		202,500			300,000			229,000
Capital contributions from parent company		23,949			21,272			27,867
Gross excess tax benefit of stock options		485			1,289			2,556
Preference stock		—			—			200,000
Pollution control revenue bonds		78,500			265,100			265,500
Senior notes issuances		500,000			850,000			850,000
Redemptions —
Preferred stock		—			(125,000	)		—
Pollution control revenue bonds		—			(11,100	)		—
Senior notes		(250,000	)		(410,000	)		(668,500	)
Other long-term debt		—			—			(103,093	)
Payment of preferred and preference stock dividends		(39,470	)		(40,899	)		(31,380	)
Payment of common stock dividends		(522,800	)		(491,300	)		(465,000	)
Other financing activities		(2,850	)		(9,369	)		(25,709	)
Net cash provided from (used for) financing activities		(34,681	)		374,988			161,571
Net Change in Cash and Cash Equivalents		339,835			(45,435	)		58,077
Cash and Cash Equivalents at Beginning of Year		28,181			73,616			15,539
Cash and Cash Equivalents at End of Year	$	368,016		$	28,181		$	73,616
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $33,112, $20,215 and $17,961 capitalized, respectively)		254,989	��		258,918			248,289
Income taxes (net of refunds)		426,390			214,368			340,951

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

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BALANCE SHEETS
At December 31, 2009 and 2008
Alabama Power Company 2009 Annual Report

Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	368,016		$	28,181
Restricted cash		36,711			80,079
Receivables —
Customer accounts receivable		322,292			350,410
Unbilled revenues		134,875			98,921
Under recovered regulatory clause revenues		37,338			153,899
Other accounts and notes receivable		33,522			44,645
Affiliated companies		61,508			70,612
Accumulated provision for uncollectible accounts		(9,551	)		(8,882	)
Fossil fuel stock, at average cost		394,511			322,089
Materials and supplies, at average cost		326,074			305,880
Vacation pay		53,607			52,577
Prepaid expenses		111,320			88,219
Other regulatory assets, current		34,347			74,825
Other current assets		6,203			12,915
Total current assets		1,910,773			1,674,370
Property, Plant, and Equipment:
In service		18,574,229			17,635,129
Less accumulated provision for depreciation		6,558,864			6,259,720
Plant in service, net of depreciation		12,015,365			11,375,409
Nuclear fuel, at amortized cost		253,308			231,862
Construction work in progress		1,256,311			1,092,516
Total property, plant, and equipment		13,524,984			12,699,787
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		59,628			50,912
Nuclear decommissioning trusts, at fair value		489,795			403,966
Miscellaneous property and investments		69,749			62,782
Total other property and investments		619,172			517,660
Deferred Charges and Other Assets:
Deferred charges related to income taxes		387,447			362,596
Prepaid pension costs		132,643			166,334
Deferred under recovered regulatory clause revenues		—			180,874
Other regulatory assets, deferred		750,492			732,367
Other deferred charges and assets		198,582			202,018
Total deferred charges and other assets		1,469,164			1,644,189
Total Assets	$	17,524,093		$	16,536,006

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

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BALANCE SHEETS
At December 31, 2009 and 2008
Alabama Power Company 2009 Annual Report

Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	100,000	$	250,079
Notes payable		—		24,995
Accounts payable —
Affiliated		194,675		178,708
Other		328,400		358,176
Customer deposits		86,975		77,205
Accrued taxes —
Accrued income taxes		14,789		18,299
Other accrued taxes		31,918		30,372
Accrued interest		65,455		56,375
Accrued vacation pay		44,751		44,217
Accrued compensation		71,286		91,856
Liabilities from risk management activities		37,844		83,873
Over recovered regulatory clause revenues		181,565		—
Other current liabilities		40,020		53,777
Total current liabilities		1,197,678		1,267,932
Long-Term Debt(See accompanying statements)		6,082,489		5,604,791
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,293,468		2,243,117
Deferred credits related to income taxes		88,705		90,083
Accumulated deferred investment tax credits		164,713		172,638
Employee benefit obligations		387,936		396,923
Asset retirement obligations		491,007		461,284
Other cost of removal obligations		668,151		634,792
Other regulatory liabilities, deferred		169,224		79,151
Deferred over recovered regulatory clause revenues		22,060		—
Other deferred credits and liabilities		37,113		45,858
Total deferred credits and other liabilities		4,322,377		4,123,846
Total Liabilities		11,602,544		10,996,569
Redeemable Preferred Stock(See accompanying statements)		341,715		341,715
Preference Stock(See accompanying statements)		343,373		343,412
Common Stockholder’s Equity(See accompanying statements)		5,236,461		4,854,310
Total Liabilities and Stockholder’s Equity		17,524,093	$	16,536,006
Commitments and Contingent Matters(See notes)

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

II-126

STATEMENTS OF CAPITALIZATION
At December 31, 2009 and 2008
Alabama Power Company 2009 Annual Report

	2009			2008			2009			2008
	(in thousands)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate (3.35% at 1/1/10) due 2042	$	206,186		$	206,186
Long-term notes payable —
Floating rate (2.34% at 1/1/09) due 2009		—			250,000
4.70% due 2010		100,000			100,000
5.10% due 2011		200,000			200,000
4.85% due 2012		500,000			500,000
5.80% due 2013		250,000			250,000
5.125% to 6.375% due 2016-2047		3,775,000			3,275,000
Total long-term notes payable		4,825,000		$	4,575,000
Other long-term debt —
Pollution control revenue bonds —
1.40% to 5.00% due 2030-2038		553,500			500,500
Variable rates (0.18% to 0.44% at 1/1/10) due 2015-2036		601,690			576,190
Total other long-term debt		1,155,190			1,076,690
Capitalized lease obligations		—			79
Unamortized debt premium (discount), net		(3,887	)		(3,085	)
Total long-term debt (annual interest requirement — $311.4 million)		6,182,489			5,854,870
Less amount due within one year		100,000			250,079
Long-term debt excluding amount due within one year		6,082,489			5,604,791			50.7	%		50.3	%

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STATEMENTS OF CAPITALIZATION(continued)
At December 31, 2009 and 2008
Alabama Power Company 2009 Annual Report

	2009			2008			2009			2008
	(in thousands)						(percent of total)
Preferred and Preference Stock:
Cumulative redeemable preferred stock
$100 par or stated value — 4.20% to 4.92%
Authorized — 3,850,000 shares
Outstanding — 475,115 shares		47,610			47,610
$1 par value — 5.20% to 5.83%
Authorized — 27,500,000 shares
Outstanding — 12,000,000 shares: $25 stated value		294,105			294,105
Preference stock
Authorized — 40,000,000 shares
Outstanding — $1 par value — 5.63% to 6.50% — 14,000,000 shares (non-cumulative) $25 stated value		343,373			343,412
Total preferred and preference stock (annual dividend requirement — $39.5 million)		685,088			685,127			5.7			6.1
Common Stockholder’s Equity:
Common stock, par value $40 per share — Authorized — 2009: 40,000,000 shares — 2008: 40,000,000 shares Outstanding — 2009: 30,537,500 shares — 2008: 25,475,000 shares		1,221,500			1,019,000
Paid-in capital		2,119,818			2,091,462
Retained earnings		1,900,526			1,753,797
Accumulated other comprehensive income (loss)		(5,383	)		(9,949	)
Total common stockholder’s equity		5,236,461			4,854,310			43.6			43.6
Total Capitalization	$	12,004,038		$	11,144,228			100.0	%		100.0	%

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

II-128

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2009, 2008, and 2007
Alabama Power Company 2009 Annual Report

	Number of										Accumulated
	Common										Other
	Shares		Common		Paid-In			Retained			Comprehensive
	Issued		Stock		Capital			Earnings			Income (Loss)			Total
	(in thousands)
Balance at December 31, 2006		12,250	$	490,000	$	2,028,963		$	1,516,245		$	(2,921	)	$	4,032,287
Net income after dividends on preferred and preference stock		—		—		—			579,582			—			579,582
Issuance of common stock		5,725		229,000		—			—			—			229,000
Capital contributions from parent company		—		—		36,441			—			—			36,441
Other comprehensive income (loss)		—		—		—			—			(1,526	)		(1,526	)
Cash dividends on common stock		—		—		—			(465,000	)		—			(465,000	)
Other		—		—		(106	)		5			—			(101	)
Balance at December 31, 2007		17,975		719,000		2,065,298			1,630,832			(4,447	)		4,410,683
Net income after dividends on preferred and preference stock		—		—		—			615,959			—			615,959
Issuance of common stock		7,500		300,000		—			—			—			300,000
Capital contributions from parent company		—		—		26,164			—			—			26,164
Other comprehensive income (loss)		—		—		—			—			(5,502	)		(5,502	)
Cash dividends on common stock		—		—		—			(491,300	)		—			(491,300	)
Other		—		—		—			(1,694	)		—			(1,694	)
Balance at December 31, 2008		25,475		1,019,000		2,091,462			1,753,797			(9,949	)		4,854,310
Net income after dividends on preferred and preference stock		—		—		—			669,536			—			669,536
Issuance of common stock		5,063		202,500		—			—			—			202,500
Capital contributions from parent company		—		—		28,356			—			—			28,356
Other comprehensive income (loss)		—		—		—			—			4,566			4,566
Cash dividends on common stock		—		—		—			(522,800	)		—			(522,800	)
Other		—		—		—			(7	)		—			(7	)
Balance at December 31, 2009		30,538	$	1,221,500	$	2,119,818		$	1,900,526		$	(5,383	)	$	5,236,461

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

II-129

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Alabama Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Net income after dividends on preferred and preference stock	$	669,536		$	615,959		$	579,582
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,943), $(4,297), and $(1,226), respectively		(3,195	)		(7,068	)		(2,017	)
Reclassification adjustment for amounts included in net income, net of tax of $4,718, $952, and $298, respectively		7,761			1,566			491
Total other comprehensive income (loss)		4,566			(5,502	)		(1,526	)
Comprehensive Income	$	674,102		$	610,457		$	578,056

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

II-130

NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2009 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 four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies — the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power), are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley.

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

The Company is subject to regulation by the Federal Energy Regulatory Commission (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, digital wireless communications, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $325 million, $321 million, and $299 million, during 2009, 2008, and 2007, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

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, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $183 million, $196 million, and $182 million, during 2009, 2008, and 2007, 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 non-fuel expenses, which were $10.2 million in 2009, $11.1 million in 2008, and $9.8 million in 2007. See Note 4 for additional information.

Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel, was terminated in July 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $1.2 million

II-131

NOTES (continued)
Alabama Power Company 2009 Annual Report

and $58.1 million in 2008 and 2007, respectively. In addition, the Company purchased synthetic fuel from AFP for use at several of the Company’s plants. Synthetic fuel purchases totaled $6.2 million and $462.1 million in 2008 and 2007, respectively.

The Company had an agreement with Southern Power under which the Company operated and maintained Plant Harris at cost. On August 1, 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power specifically requested services. In 2009, 2008, and 2007, the Company billed Southern Power $0.9 million, $0.9 million, and $2.4 million, respectively, under these agreements. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2009, 2008, and 2007 totaled $61.6 million, $63.2 million, and $66.3 million, respectively. The Company also provides the fuel, at cost, associated with the PPA. The fuel cost recognized by the Company was $62.5 million in 2009, $119.6 million in 2008, and $108.1 million in 2007. 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, 2009, 2008, and 2007. See Note 3 under “Retail Regulatory Matters” and Note 7 under “Purchased Power Commitments” for additional information.

Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO).

The traditional 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.

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate 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:

	2009			2008			Note
	(in millions)
Deferred income tax charges	$	387		$	363			(a	)
Loss on reacquired debt		74			80			(b	)
Vacation pay		54			53			(c, k)
Under/(over) recovered regulatory clause revenues		(166	)		335			(d	)
Fuel-hedging (realized and unrealized) losses		45			95			(e	)
Other assets		8			7			(f, g	)
Asset retirement obligations		(43	)		18			(a	)
Other cost of removal obligations		(668	)		(635	)		(a	)
Deferred income tax credits		(89	)		(90	)		(a	)
Fuel-hedging (realized and unrealized) gains		(1	)		(4	)		(e	)
Mine reclamation and remediation		(12	)		(14	)		(h	)
Nuclear outage		(27	)		(8	)		(d	)
Deferred purchased power		(8	)		(20	)		(g	)
Natural disaster reserve		(75	)		(33	)		(i	)
Other liabilities		(3	)		(4	)		(d	)
Underfunded retiree benefit plans		657			614			(j, k	)
Total assets (liabilities), net	$	133		$	757

Note:	The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal assets and 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 assets and liabilities will be settled and trued up following completion of the related activities.
(b)	Recovered over the remaining life of the original issue, which may range up to 50 years.
(c)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

(d)	Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding five years.
(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally does not exceed three years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause.
(f)	Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects.
(g)	Recovered over the life of the PPA for periods up to 13 years.
(h)	Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.
(i)	Recovered as storm restoration expenses are incurred, as approved by the Alabama PSC.
(j)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
(k)	Not earning a return as offset in rate base by a corresponding asset or liability.

In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income 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 to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Retail Regulatory Matters” for additional information.

Revenues

Energy and other revenues are recognized as services are provided. Wholesale 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 balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under “Retail Regulatory Matters — Fuel Cost Recovery” and “Retail Regulatory Matters — Rate CNP” for additional information.

The Company has a diversified base of customers. No single customer comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions 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. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information.

Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

Property, Plant, and Equipment

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

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NOTES (continued)
Alabama Power Company 2009 Annual Report

The Company’s property, plant, and equipment consisted of the following at December 31:

	2009		2008
	(in millions)
Generation	$	9,627	$	9,096
Transmission		2,702		2,559
Distribution		5,046		4,827
General		1,187		1,141
Plant acquisition adjustment		12		12
Total plant in service	$	18,574	$	17,635

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 nuclear refueling outage costs in advance of the unit’s next refueling outage. The refueling cycle is 18 months for each unit. During 2009, the Company accrued $47.5 million for the applicable refueling cycles and paid $29.6 million for an outage at Plant Farley Unit 1. There was no outage at Plant Farley Unit 2 in 2009. At December 31, 2009, the reserve balance totaled $27.1 million and is included in the balance sheet in other regulatory liabilities.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2% in 2009 and 2008 and 3.1% in 2007. 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. 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.

On June 25, 2009, the Company submitted an offer of settlement and stipulation to the FERC relating to the 2008 depreciation study that was filed in October 2008. The settlement offer withdraws the requests for authorization to use updated depreciation rates. In lieu of the new rates, the Company is using those depreciation rates employed prior and up to January 1, 2009 that were previously approved by the FERC. On September 30, 2009, the FERC issued an order approving the settlement offer.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. 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 are reflected in the balance sheets as a regulatory liability.

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, 2009 was $490 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has 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 differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations, and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See “Nuclear Decommissioning” for further information on amounts included in rates.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

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

	2009			2008
	(in millions)
Balance beginning of year	$	461		$	506
Liabilities incurred		—			—
Liabilities settled		(1	)		(2	)
Accretion		31			31
Cash flow revisions(a)		—			(74	)
Balance end of year	$	491		$	461

(a) Updated based on results from 2008 Nuclear Decommissioning Study

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 (the 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 Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. While the Company is allowed to prescribe an overall investment policy to the Funds’ managers, the Company is not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the Company’s management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the investment return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized, unrealized, or identified as other-than-temporary, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Fair value adjustments, realized gains, and other-than-temporary impairment losses are determined on a specific identification basis.

At December 31, 2009, investment securities in the Funds totaled $488.4 million consisting of equity securities of $345.6 million, debt securities of $134.3 million, and $8.5 million of other securities. At December 31, 2008, investment securities in the Funds totaled $402.9 million consisting of equity securities of $256.7 million, debt securities of $135.3 million, and $10.9 million of other securities. These amounts exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases.

Sales of the securities held in the Funds resulted in cash proceeds of $243.8 million, $299.6 million, and $333.4 million in 2009, 2008, and 2007, respectively, all of which were reinvested. For 2009, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $96.2 million, of which $79.9 million related to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding the Funds’ expenses, were $(134.4) million. Realized gains and other-than-temporary impairment losses were $34.6 million and $(37.2) million, respectively, in 2007. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired.

Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan 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.

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Alabama Power Company 2009 Annual Report

At December 31, 2009, the accumulated provisions for decommissioning were as follows:

	(in millions)
External trust funds	$	490
Internal reserves		25
Total	$	515

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 2008 for Plant Farley was as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2065

	(in millions)
Site study costs:
Radiated structures	$	1,060
Non-radiated structures		72
Total	$	1,132

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, the Company’s decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2013.

Amounts previously contributed to the external trust fund are currently projected to be adequate to meet the decommissioning obligations. 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.

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC, which 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 equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.2% in 2009 and 2008 and 9.4% in 2007. AFUDC, net of income tax, as a percent of net income after dividends on preferred and preference stock was 14.9% in 2009, 9.4% in 2008, and 8.0% in 2007.

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 loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

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Alabama Power Company 2009 Annual Report

Natural Disaster Reserve

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly natural disaster reserve (NDR) charge to customers consisting of two components. 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 second component of the NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, 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. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant.

In addition to the monthly NDR charge, the Company accrued $39.6 million of discretionary reserve in 2009 resulting in an accumulated balance of approximately $75 million in the reserve for future storms as of December 31, 2009. This reserve is included in other regulatory liabilities, deferred in the balance sheets. Effective February 2010, billings will be reduced to $0.37 per month per non-residential customer account and $0.15 per month per residential customer account, consistent with the Alabama PSC order to maintain the target NDR balance. The Company has fully recovered its deferred storm costs; therefore, rates do not include the second component of the NDR charge.

As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, any change in revenue and expense will not have an effect on net income but will decrease operating cash flows related to the NDR charge in 2010 when compared to 2009.

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, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. 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. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2009.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

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.

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 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 “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, the Company is not considered 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 included in Long-term Debt in the balance sheets.

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). No contributions to the defined benefit plan are expected for the year ending December 31, 2010. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2010, postretirement trust contributions are expected to total approximately $11 million.

The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to accounting standards related to defined postretirement benefit plans, the Company was required to change the measurement date for its defined postretirement benefit plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the Company adopted the measurement date provisions effective January 1, 2008 resulting in an increase in long-term liabilities of $5 million and an increase in prepaid pension costs of approximately $11 million.

Pension Plans

The total accumulated benefit obligation for the pension plans was $1.6 billion in 2009 and $1.4 billion in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,460		$	1,420
Service cost		34			43
Interest cost		96			109
Benefits paid		(77	)		(94	)
Actuarial loss (gain)		162			(18	)
Balance at end of year		1,675			1,460
Change in plan assets
Fair value of plan assets at beginning of year		1,539			2,318
Actual return (loss) on plan assets		245			(692	)
Employer contributions		5			7
Benefits paid		(77	)		(94	)
Fair value of plan assets at end of year		1,712			1,539
Prepaid pension asset, net	$	37		$	79

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Alabama Power Company 2009 Annual Report

At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension plans were $1.6 billion and $95 million, respectively. All pension plan assets are related to the qualified pension 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). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s pension plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		29	%		33	%		34	%
International equity		28			29			23
Fixed income		15			15			14
Special situations		3			—			—
Real estate investments		15			13			19
Private equity		10			10			10
Total		100	%		100	%		100	%

The investment strategy for plan assets related to the Company’s defined benefit pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

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Alabama Power Company 2009 Annual Report

The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2009:	(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	339		$	141	$	—	$	480
International equity*		439			44		—		483
Fixed income:
U.S. Treasury, government, and agency bonds		—			127		—		127
Mortgage- and asset-backed securities		—			34		—		34
Corporate bonds		—			85		—		85
Pooled funds		—			3		—		3
Cash equivalents and other		1			104		—		105
Special situations		—			—		—		—
Real estate investments		53			—		166		219
Private equity		—			—		169		169
Total	$	832		$	538	$	335	$	1,705
Liabilities:
Derivatives		(1	)		—		—		(1	)
Total	$	831		$	538	$	335	$	1,704

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	318		$	129	$	—	$	447
International equity*		285			26		—		311
Fixed income:
U.S. Treasury, government, and agency bonds		—			133		—		133
Mortgage- and asset-backed securities		—			63		—		63
Corporate bonds		—			86		—		86
Pooled funds		—			1		—		1
Cash equivalents and other		7			61		—		68
Special situations		—			—		—		—
Real estate investments		43			—		254		297
Private equity		—			—		148		148
Total	$	653		$	499	$	402	$	1,554
Liabilities:
Derivatives		(2	)		—		—		(2	)
Total	$	651		$	499	$	402	$	1,552

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk.

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Alabama Power Company 2009 Annual Report

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in millions)
Beginning balance	$	254		$	148	$	316		$	157
Actual return on investments:
Related to investments held at year end		(72	)		13		(51	)		(43	)
Related to investments sold during the year		(20	)		3		1			8
Total return on investments		(92	)		16		(50	)		(35	)
Purchases, sales, and settlements		4			5		(12	)		26
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	166		$	169	$	254		$	148

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the consolidated balance sheets related to the Company’s pension plans consist of:

	2009			2008
	(in millions)
Prepaid pension costs	$	133		$	166
Other regulatory assets, deferred		549			479
Other current liabilities		(6	)		(6	)
Employee benefit obligations		(90	)		(81	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2010.

	Prior ServiceCost		Net(Gain)Loss
	(in millions)
Balance at December 31, 2009:
Regulatory assets	$	50	$	499
Balance at December 31, 2008:
Regulatory assets	$	58	$	421
Estimated amortization in net periodic pension cost in 2010:
Regulatory assets	$	9	$	2

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NOTES (continued)
Alabama Power Company 2009 Annual Report

The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory			Regulatory
	Assets			Liabilities
	(in millions)
Balance at December 31, 2007	$	43		$	(423	)
Net loss		441			433
Change in prior service costs		—			—
Reclassification adjustments:
Amortization of prior service costs		(2	)		(10	)
Amortization of net gain		(3	)		—
Total reclassification adjustments		(5	)		(10	)
Total change		436			423
Balance at December 31, 2008		479			—
Net loss		79			—
Change in prior service costs		1			—
Reclassification adjustments:
Amortization of prior service costs		(9	)		—
Amortization of net gain		(1	)		—
Total reclassification adjustments		(10	)		—
Total change		70			—
Balance at December 31, 2009	$	549		$	—

Components of net periodic pension cost (income) were as follows:

	2009			2008			2007
	(in millions)
Service cost	$	34		$	35		$	35
Interest cost		96			87			82
Expected return on plan assets		(164	)		(160	)		(146	)
Recognized net (gain) loss		1			2			2
Net amortization		9			10			10
Net periodic pension (income)	$	(24	)	$	(26	)	$	(17	)

Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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, 2009, estimated benefit payments were as follows:

	Benefit Payments
	(in millions)
2010	$	87
2011		91
2012		95
2013		101
2014		108
2015 to 2019		610

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NOTES (continued)
Alabama Power Company 2009 Annual Report

Other Postretirement Benefits

Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	446		$	480
Service cost		6			9
Interest cost		29			37
Benefits paid		(26	)		(30	)
Actuarial loss (gain)		19			(53	)
Plan amendments		(15	)		—
Retiree drug subsidy		2			3
Balance at end of year		461			446
Change in plan assets
Fair value of plan assets at beginning of year		252			297
Actual return (loss) on plan assets		47			(75	)
Employer contributions		20			57
Benefits paid		(24	)		(27	)
Fair value of plan assets at end of year		295			252
Accrued liability (recognized in the balance sheet)	$	(166	)	$	(194	)

Other postretirement benefit 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. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		47	%		42	%		31	%
International equity		12			16			13
Domestic fixed income		32			35			46
Special situations		1			—			—
Real estate investments		5			4			7
Private equity		3			3			3
Total		100	%		100	%		100	%

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is comprised of domestic bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Trust-owned life insurance.Some of the Company’s taxable trusts invest in these investments in order to minimize the impact of taxes on the portfolio.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

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Alabama Power Company 2009 Annual Report

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	54	$	8	$	—	$	62
International equity*		24		2		—		26
Fixed income:
U.S. Treasury, government, and agency bonds		—		7		—		7
Mortgage- and asset-backed securities		—		2		—		2
Corporate bonds		—		5		—		5
Pooled funds		—		—		—		—
Cash equivalents and other		—		23		—		23
Trust-owned life insurance		—		144		—		144
Special situations		—		—		—		—
Real estate investments		3		—		9		12
Private equity		—		—		10		10
Total	$	81	$	191	$	19	$	291

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2008:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	33	$	7	$	—	$	40
International equity*		16		1		—		17
Fixed income:
U.S. Treasury, government, and agency bonds		—		7		—		7
Mortgage- and asset-backed securities		—		4		—		4
Corporate bonds		—		5		—		5
Pooled funds		—		—		—		—
Cash equivalents and other		—		48		—		48
Trust-owned life insurance		—		105		—		105
Special situations		—		—		—		—
Real estate investments		2		—		15		17
Private equity		—		—		8		8
Total	$	51	$	177	$	23	$	251

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well diversified with no significant concentrations of risk.

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Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in millions)
Beginning balance	$	15		$	8	$	17		$	9
Actual return on investments:
Related to investments held at year end		(5	)		2		(2	)		(2	)
Related to investments sold during the year		(1	)		—		—			—
Total return on investments		(6	)		2		(2	)		(2	)
Purchases, sales, and settlements		—			—		—			1
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	9		$	10	$	15		$	8

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of:

	2009			2008
	(in millions)
Regulatory assets	$	108		$	135
Employee benefit obligations		(166	)		(194	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2010.

	Prior Service		Net		Transition
	Cost		(Gain)Loss		Obligation
	(in millions)
Balance at December 31, 2009:
Regulatory asset	$	33	$	67	$	8
Balance at December 31, 2008:
Regulatory asset	$	49	$	71	$	15
Estimated amortization as net periodic postretirement cost in 2010:
Regulatory asset	$	4	$	—	$	3

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Alabama Power Company 2009 Annual Report

The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory Assets
	(in millions)
Balance at December 31, 2007	$	95
Net loss		50
Change in prior service costs/transition obligation		—
Reclassification adjustments:
Amortization of transition obligation		(5	)
Amortization of prior service costs		(5	)
Amortization of net gain		—
Total reclassification adjustments		(10	)
Total change		40
Balance at December 31, 2008		135
Net gain		(4	)
Change in prior service costs/transition obligation		(15	)
Reclassification adjustments:
Amortization of transition obligation		(4	)
Amortization of prior service costs		(4	)
Amortization of net gain		—
Total reclassification adjustments		(8	)
Total change		(27	)
Balance at December 31, 2009	$	108

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

	2009			2008			2007
	(in millions)
Service cost	$	6		$	7		$	7
Interest cost		29			29			28
Expected return on plan assets		(24	)		(22	)		(19	)
Net amortization		8			9			11
Net postretirement cost	$	19		$	23		$	27

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2009, 2008, and 2007 by approximately $9.0 million, $10.7 million, and $10.7 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 APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

	Benefit Payments		Subsidy Receipts			Total
	(in millions)
2010	$	29	$	(3	)	$	26
2011		32		(3	)		29
2012		34		(3	)		31
2013		36		(4	)		32
2014		37		(4	)		33
2015 to 2019		194		(28	)		166

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Alabama Power Company 2009 Annual Report

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual salary increase of 3.50%.

	2009			2008			2007
Discount rate:
Pension plans		5.93	%		6.75	%		6.30	%
Other postretirement benefit plans		5.84			6.75			6.30
Annual salary increase		4.18			3.75			3.75
Long-term return on plan assets:
Pension plans		8.50			8.50			8.50
Other postretirement benefit plans		7.52			7.66			7.68

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2009 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	29	$	27
Service and interest costs		2		2

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $19 million, $18 million, and $17 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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.

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Alabama Power Company 2009 Annual Report

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 the Company, 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. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to each of the traditional operating companies. After the Company was dismissed from the original action, the EPA filed a separate action in January 2001 against the Company in the U.S. District Court for the Northern District of Alabama. In the lawsuit against the Company, the EPA alleges that NSR violations occurred at five coal-fired generating facilities operated by the Company. The civil action requests penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between the Company and the EPA, resolving a portion of the Company’s lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of the Company with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the

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Alabama Power Company 2009 Annual Report

Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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 releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that the Company possesses or has exercised any market power. The agreement likewise does not require the Company to make any refunds related to sales during the 15-month refund period. Under the agreement, the Company will donate $0.6 million to nonprofit organizations in the State of Alabama for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on

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Alabama Power Company 2009 Annual Report

behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

Nuclear Fuel Disposal Costs

The Company has a contract with the United States, acting through 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.

In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal, and in February 2008, filed a motion to stay the appeal. In April 2008, the U.S. Court of Appeals for the Federal Circuit granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. The U.S. Court of Appeals for the Federal Circuit has left the stay of appeals in place pending the decision in an appeal of another case involving spent nuclear fuel contracts.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2009 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

An on-site dry spent fuel storage facility at Plant Farley is operational and can be expanded to accommodate spent fuel through the expected life of the plant.

Retail Regulatory Matters

Rate RSE

Rate RSE adjustments are 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% per year and any annual adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common equity is projected to be between 13.0% and 14.5%. 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.

In October 2008, the Alabama PSC approved a corrective rate package, effective January 2009, that primarily provides for adjustments associated with customer charges to certain existing rate structures. The Company agreed to a moratorium on any increase in rates in 2009 under the Rate RSE.

On December 1, 2009, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2010. The Rate RSE increase for 2010 is 3.24%, or $152 million annually, and was effective in January 2010. The revenue adjustment under the Rate RSE is largely attributable to the costs associated with fossil capacity which is currently dedicated to certain long-term wholesale contracts that expire during 2010. Retail cost of service for 2010 reflects the costs for that portion of the year in which this capacity is no longer committed to wholesale. In an Alabama PSC order dated January 5, 2010, the Alabama PSC acknowledged that a full calendar year of costs for these units would be reflected in the Rate RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the maximum increase for 2011 cannot exceed 4.76%.

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Alabama Power Company 2009 Annual Report

Rate CNP

The Company’s retail rates, approved by the Alabama PSC, 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 a Rate CNP. There was no adjustment to the Rate CNP to recover certificated PPA costs in 2007, 2008, or 2009. Effective April 2010, Rate CNP will be reduced approximately $70 million annually, primarily due to the expiration on May 31, 2010, of the PPA with Southern Power covering the capacity of Plant Harris Unit 1.

Rate CNP also allows for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism is based on forward looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased approximately 0.6% in January 2007 and 2.4% in January 2008 due to environmental costs. In October 2008, the Company agreed to defer collection of any increase in rates under this portion of Rate CNP, which permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010. The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no significant effect on the Company’s revenues or net income. On December 1, 2009, the Company made its Rate CNP environmental submission of projected data for calendar year 2010, resulting in an increase to retail rates of approximately 4.3%, or an additional $195 million annually, based upon projected billings. Under the terms of the rate mechanism, this adjustment became effective in January 2010. The Rate CNP environmental adjustment is primarily attributable to scrubbers being placed in service during 2010 at four of the Company’s generating units.

Fuel Cost Recovery

The Company has established fuel cost recovery rates under Rate ECR approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. The Company, along with the Alabama PSC, will continue to monitor the over recovered fuel cost balance to determine whether an additional adjustment to billing rates is required.

In June 2007, the Alabama PSC ordered the Company to increase its Rate ECR factor to 3.100 cents per kilowatt-hour (KWH) effective with billings beginning July 2007. In October 2008, the Alabama PSC approved an increase in the Company’s Rate ECR factor to 3.983 cents per KWH effective with billings beginning October 2008.

On June 2, 2009, the Alabama PSC approved a decrease in the Company’s Rate ECR factor to 3.733 cents per KWH for billings beginning June 9, 2009. On December 1, 2009, the Alabama PSC approved a decrease in the Company’s Rate ECR factor to 2.731 cents per KWH for billings beginning January 2010 through December 2011. The Alabama PSC further approved an additional reduction in the Rate ECR factor of 0.328 cents per KWH for the billing months of January 2010 through December 2010 resulting in a Rate ECR factor of 2.403 cents per KWH for such 12-month period. For billing months beginning January 2012, the Rate ECR factor shall be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial statements, are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, the approved decreases in the Rate ECR factor will have no significant effect on the Company’s net income, but will decrease operating cash flows related to fuel cost recovery in 2010 when compared to 2009.

As of December 31, 2009, the Company had an over recovered fuel balance of approximately $199.6 million, of which approximately $22.1 million is included in deferred over recovered regulatory clause revenues in the balance sheets. As of December 31, 2008, the Company had an under recovered fuel balance of approximately $305.8 million, of which approximately $180.9 million is included in deferred under recovered regulatory clause revenues in the balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs or recovery of under recovered fuel costs.

Natural Disaster Reserve

Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly NDR charge to customers consisting of two components. 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 second component of the NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total NDR charge consisting of

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Alabama Power Company 2009 Annual Report

both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has discretionary authority to accrue certain additional amounts as circumstances warrant.

In addition to the monthly NDR charge, the Company accrued $39.6 million of discretionary reserve in 2009 resulting in an accumulated balance of approximately $75 million in the reserve for future storms as of December 31, 2009. This reserve is included in other regulatory liabilities, deferred in the balance sheets. Effective February 2010, billings will be reduced to $0.37 per month per non-residential customer account and $0.15 per month per residential customer account, consistent with the Alabama PSC order to maintain the target NDR balance. The Company has fully recovered its deferred storm costs, therefore, rates do not include the second component of the NDR charge.

As revenue from the NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, any change in revenue and expense will not have an effect on net income but will decrease operating cash flows related to the NDR charge in 2010 when compared to 2009.

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 years’ notice. The Company’s share of purchased power totaled $82.1 million in 2009, $124 million in 2008, and $105 million in 2007, 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, 2009, the capitalization of SEGCO consisted of $85 million of equity and $74 million of long-term debt on which the annual interest requirement is $3.2 million. SEGCO paid no dividends in 2009, $7.8 million in 2008, and $2.6 million in 2007, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% 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, 2009 is as follows:

	Total Megawatt		Company			Company		Accumulated
Facility	Capacity		Ownership			Investment		Depreciation
						(in millions)
Greene County		500		60.00	%(1)	$	137	$	71
Plant Miller
Units 1 and 2		1,320		91.84	%(2)		1,063		449

(1)	Jointly owned with an affiliate, Mississippi Power.
(2)	Jointly owned with PowerSouth.

At December 31, 2009, the Company’s Plant Miller portion of construction work in progress was $243.6 million.

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 and the Company is responsible for providing its own financing.

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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 and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability. In addition, the Company files a separate company income tax return for the State of Tennessee.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2009			2008		2007
	(in millions)
Federal —
Current	$	374		$	198	$	287
Deferred		(41	)		121		17
	$	333		$	319	$	304
State —
Current	$	76		$	43	$	43
Deferred		(25	)		6		4
		51			49		47
Total	$	384		$	368	$	351

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:

	2009		2008
	(in millions)
Deferred tax liabilities:
Accelerated depreciation	$	2,010	$	1,908
Property basis differences		376		343
Premium on reacquired debt		30		33
Pension and other benefits		184		175
Fuel clause under recovered		—		140
Regulatory assets associated with employee benefit obligations		295		286
Regulatory assets associated with asset retirement obligations		208		199
Other		82		67
Total		3,185		3,151
Deferred tax assets:
Federal effect of state deferred taxes		88		126
State effect of federal deferred taxes		107		104
Unbilled revenue		29		34
Storm reserve		23		4
Pension and other benefits		334		330
Other comprehensive losses		9		13
Fuel clause over recovered		75
Asset retirement obligations		208		199
Other		93		82
Total		966		892
Total deferred tax liabilities, net		2,219		2,259
Portion included in current assets (liabilities), net		74		(16	)
Accumulated deferred income taxes in the balance sheets	$	2,293	$	2,243

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NOTES (continued)
Alabama Power Company 2009 Annual Report

At December 31, 2009, the Company’s tax-related regulatory assets and liabilities were $387 million and $89 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, 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.

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 $8.0 million in each of 2009, 2008, and 2007. At December 31, 2009, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		3.0			3.1			3.2
Non-deductible book depreciation		0.8			0.9			0.9
Differences in prior years’ deferred and current tax rates		(0.2	)		(0.1	)		(0.2	)
AFUDC-equity		(2.5	)		(1.6	)		(1.3	)
Production activities deduction		(0.8	)		(0.5	)		(0.6	)
Other		(0.2	)		(0.8	)		(0.7	)
Effective income tax rate		35.1	%		36.0	%		36.3	%

AFUDC increased in 2009 due to increases in the amount of construction work in progress related to environmental mandates at generating facilities and transmission, distribution, and general plant projects compared to the prior years. See Note 1 under “Allowance for Funds Used During Construction (AFUDC)” for additional information.

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U. S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, the Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits increased by $3 million, resulting in a balance of $6 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009		2008			2007
			(in millions)
Unrecognized tax benefits at beginning of year	$	3	$	5		$	1
Tax positions from current periods		2		1			2
Tax positions from prior periods		1		(2	)		2
Reductions due to settlements		—		(1	)		—
Reductions due to expired statute of limitations		—		—			—
Balance at end of year	$	6	$	3		$	5

The tax positions from current periods increase for 2009 relate primarily to the production activities deduction tax position and other miscellaneous uncertain tax positions. The tax positions increase from prior periods for 2009 relates primarily to the production activities deduction tax position. See “Effective Tax Rate” above for additional information.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

Impact on the Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
	(in millions)
Tax positions impacting the effective tax rate	$	6	$	3	$	5
Tax positions not impacting the effective tax rate		—		—		—
Balance of unrecognized tax benefits	$	6	$	3	$	5

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008			2007
	(in millions)
Interest accrued at beginning of year	$	0.3	$	0.4		$	—
Interest reclassified due to settlements		—		(0.3	)		—
Interest accrued during the year		—		0.2			0.4
Balance at end of year	$	0.3	$	0.3		$	0.4

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

6. FINANCING

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 $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as Long-term Debt Payable. 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, 2009, preferred securities of $200 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

At December 31, 2009, the Company had a scheduled maturity of senior notes due within one year totaling $100 million. At December 31, 2008, the Company had scheduled maturities and redemptions of senior notes due within one year totaling $250 million.

Maturities of senior notes through 2014 applicable to total long-term debt are as follows: $100 million in 2010; $200 million in 2011; $500 million in 2012; $250 million in 2013; and none in 2014.

Pollution Control Revenue Bonds

Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of solid waste disposal 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. The Company incurred obligations related to the issuance of $78.5 million of pollution control revenue bonds in 2009. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

Senior Notes

The Company issued a total of $500 million of unsecured senior notes in 2009. The proceeds of these issuances were used to repay short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program.

At December 31, 2009 and 2008, the Company had $4.8 billion and $4.6 billion, respectively, of senior notes outstanding. These senior notes are effectively subordinate to all secured debt of the Company which amounted to approximately $153 million at December 31, 2009.

Preference and Common Stock

In 2009, the Company issued no new shares of preference stock. The Company issued 5,062,500 new shares of common stock to Southern Company at $40.00 per share and realized proceeds of $202.5 million. The proceeds of these issuances were used for general corporate purposes.

Outstanding Classes of Capital Stock

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The preferred stock and Class A preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as “Redeemable Preferred Stock” in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company’s board. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock, Class A preferred stock, and preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance).

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Assets Subject to Lien

The Company has granted liens on certain property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $153 million as of December 31, 2009.

Bank Credit Arrangements

The Company maintains committed lines of credit in the amount of $1.3 billion, of which $481 million will expire at various times during 2010, $25 million will expire in 2011, and $765 will expire in 2012. $372 million of the credit facilities expiring in 2010 allow for the execution of one-year term loans. These credit facilities provide liquidity support to the Company’s commercial paper borrowings and $608 million are dedicated to funding purchase obligations relating to variable rate pollution control revenue bonds. Subsequent to December 31, 2009, two remarketings of pollution control revenue bonds increased that amount to $744 million.

Most 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 average less than¹/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.

Most of the Company’s credit arrangements with banks have covenants that limit the Company’s debt to 65% 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, 2009, 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.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

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 uncommitted credit arrangements. As of December 31, 2009, the Company had no commercial paper outstanding. As of December 31, 2008, the Company had $25 million of commercial paper outstanding. During 2009 and 2008, the peak amount outstanding for short-term borrowings was $237 million and $301 million, respectively. The average amount outstanding in 2009 and 2008 was $30 million and $40 million, respectively. The average annual interest rate on short-term borrowings was 0.23% in 2009 and 2.31% in 2008. Short-term borrowings are included in notes payable in the balance sheets.

At December 31, 2009, the Company had regulatory approval to have outstanding up to $2.0 billion of short-term borrowings.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $1.0 billion in 2010, $1.0 billion in 2011, and $1.1 billion in 2012. These amounts include $73 million, $48 million, and $51 million for 2010, 2011, and 2012, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included under “Fuel Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2009, 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 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, which are subject to price escalation, are made at various intervals based on actual operating hours of the respective units. Total remaining payments to GE under these agreements for facilities owned are currently estimated at $256 million over the remaining life of the agreements, which are currently estimated to range up to 10 years. 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.

Limestone Commitments

As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 2.9 million tons, equating to approximately $127 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $11 million in 2010, $15 million in 2011, $15 million in 2012, $16 million in 2013, and $16 million in 2014.

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Alabama Power Company 2009 Annual Report

Fuel Commitments

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions 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, 2009. Total estimated minimum long-term commitments at December 31, 2009 were as follows:

	Commitments
	Natural Gas		Coal		Nuclear Fuel
	(in millions)
2010	$	413	$	1,420	$	73
2011		275		894		48
2012		176		695		51
2013		141		516		37
2014		113		407		23
2015 and thereafter		148		975		90
Total commitments	$	1,266	$	4,907	$	322

Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense totaled $78 million in 2009, $70 million in 2008, and $65 million in 2007.

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 traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

Purchased Power Commitments

The Company has entered into various long-term commitments for the purchase of capacity and energy. Total estimated minimum long-term obligations at December 31, 2009 were as follows:

	Commitments
	Affiliated		Non-Affiliated		Total
			(in millions)
2010	$	13	$	26	$	39
2011		—		30		30
2012		—		30		30
2013		—		31		31
2014		—		36		36
2015 and thereafter		—		337		337
Total commitments	$	13	$	490	$	503

Certain PPAs reflected in the table are accounted for as operating leases.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

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 $26.9 million in 2009, $26.1 million in 2008, and $27.7 million in 2007. Of these amounts, $20.3 million, $19.2 million, and $20.5 million for 2009, 2008, and 2007, respectively, relate to the rail car leases and are recoverable through the Company’s Rate ECR. At December 31, 2009, estimated minimum rental commitments for non-cancelable operating leases were as follows:

	Minimum Lease Payments
	Rail Cars		Vehicles & Other		Total
			(in millions)
2010	$	16	$	6	$	22
2011		7		4		11
2012		7		3		10
2013		4		1		5
2014		3		—		3
2015 and thereafter		10		—		10
Total *	$	47	$	14	$	61

^* Total does not include payments related to a non-affiliated PPA that is accounted for as an operating lease. Obligations related to this agreement are included in the above purchased power commitments table.

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 2010 and 2013, and the Company’s maximum obligations are $61.2 million and $18.6 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. However, due to the recessionary economy, it is possible that the fair market value of the leased property would not eliminate the Company’s payments under the residual value obligations on the leases expiring in 2010.

Guarantees

At December 31, 2009, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets 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, 2009, there were 1,412 current and former employees of the Company participating in the stock option plan and there were 21 million shares of Southern Company common stock remaining available for awards under this plan. 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. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. 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. For certain stock option awards, a change in control will provide accelerated vesting.

The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:

Year Ended December 31	2009			2008			2007
Expected volatility		15.6	%		13.1	%		14.8	%
Expected term(in years)		5.0			5.0			5.0
Interest rate		1.9	%		2.8	%		4.6	%
Dividend yield		5.4	%		4.5	%		4.3	%
Weighted average grant-date fair value	$	1.80		$	2.37		$	4.12

The Company’s activity in the stock option plan for 2009 is summarized below:

	Shares Subject			Weighted Average
	to Option			Exercise Price
Outstanding at December 31, 2008		6,809,196		$	31.61
Granted		2,084,772			31.39
Exercised		(137,082	)		19.79
Cancelled		(7,412	)		29.40
Outstanding at December 31, 2009		8,749,474		$	31.74
Exercisable at December 31, 2009		5,791,523		$	31.10

The number of stock options vested and expected to vest in the future, as of December 31, 2009 was not significantly different from the number of stock options outstanding at December 31, 2009 as stated above. As of December 31, 2009, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.0 years and 4.6 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $20.8 million and $17.1 million, respectively.

As of December 31, 2009, there was $1.0 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 11 months.

For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option awards recognized in income was $3.8 million, $3.1 million, and $4.9 million, respectively, with the related tax benefit also recognized in income of $1.4 million, $1.2 million, and $1.9 million, respectively.

The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $1.7 million, $5.2 million, and $9.7 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.7 million, $2.0 million, and $3.7 million, respectively, for the years ended December 31, 2009, 2008, and 2007.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments 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 $12.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 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 commercial nuclear reactors. The Company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 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 $235 million per incident but not more than an aggregate of $35 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

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. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses.

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. The Company purchases the maximum limit allowed by NEIL and has elected a 12-week deductible 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 $38 million.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

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. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

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NOTES (continued)
Alabama Power Company 2009 Annual Report

As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts:(a)
Domestic equity		296		49		—		345
U.S. Treasury and government agency securities		11		5		—		16
Corporate bonds		—		76		—		76
Mortgage and asset backed securities		—		42		—		42
Other		—		9		—		9
Cash equivalents and restricted cash		346		—		—		346
Total	$	653	$	182	$	—	$	835
Liabilities:
Energy-related derivatives	$	—	$	45	$	—	$	45
Interest rate derivatives		—		4		—		4
Total	$	—	$	49	$	—	$	49

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 11 herein for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. See Note 1 under “Nuclear Decommissioning” for additional information. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. All of these financial instruments and investments are valued primarily using the market approach.

As of December 31, 2009, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

			Unfunded	Redemption	Redemption
As of December 31, 2009:	Fair Value		Commitments	Frequency	Notice Period
	(in millions)
Nuclear decommissioning trusts:
Trust owned life insurance	$	78	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		346	None	Daily	Not applicable

The nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI via death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the tables above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

II-162

NOTES (continued)
Alabama Power Company 2009 Annual Report

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company’s investment in the money market funds.

As of December 31, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2009	$	6,182	$	6,357
2008		5,855		5,784

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

11. DERIVATIVES

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 its exposures, where possible, 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. The Company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

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 manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of three methods:

• Regulatory Hedges– Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause.

• Cash Flow Hedges– Gains and losses on energy-related derivatives designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income (OCI) before being recognized in income in the same period as the hedged transactions are reflected in earnings.

• Not Designated– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

II-163

NOTES (continued)
Alabama Power Company 2009 Annual Report

At December 31, 2009, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Net
Purchased
mmBtu*	Longest Hedge	Longest Non-Hedge
(in millions)	Date	Date
37	2014	—

* mmBtu – million British thermal units

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2010 are immaterial.

Interest Rate Derivatives

The Company also enters into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings.

At December 31, 2009, the Company had outstanding interest rate derivatives designated as cash flow hedges of existing debt as follows:

		Weighted		Fair Value
Notional	Variable Rate	Average	Hedge Maturity	Gain (Loss)
Amount	Received	Fixed Rate Paid	Date	December 31, 2009
(in millions)				(in millions)
$576	SIFMA Index*	2.69%	February 2010	$(4)

* Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA)

The estimated pre-tax loss that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2010 is $1.0 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035.

II-164

NOTES (continued)
Alabama Power Company 2009 Annual Report

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

	Asset Derivatives					Liability Derivatives
	Balance Sheet					Balance Sheet
Derivative Category	Location	2009		2008		Location	2009		2008
		(in millions)					(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:	Other current assets	$	1	$	4	Liabilities from risk management activities	$	34	$	75
	Other deferred charges and assets		—		—	Other deferred credits and liabilities		11		21
Total derivatives designated as hedging instruments for regulatory purposes		$	1	$	4		$	45	$	96
Derivatives designated as hedging instruments in cash flow hedges
Interest rate derivatives:	Other current assets		—		—	Liabilities from risk management activities		4		9
	Other deferred charges and assets		—		—	Other deferred credits and liabilities		—		2
Total derivatives designated as hedging instruments in cash flow hedges		$	—	$	—		$	4	$	11
Total		$	1	$	4		$	49	$	107

All derivative instruments are measured at fair value. See Note 10 for additional information.

At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

	Unrealized Losses							Unrealized Gains
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in millions)							(in millions)
Energy-related derivatives:	Other regulatory assets, current	$	(34	)	$	(75	)	Other regulatory liabilities, current	$	1	$	4
	Other regulatory assets, deferred		(11	)		(21	)	Other regulatory liabilities, deferred		—		—
Total energy-related derivative gains (losses)		$	(45	)	$	(96	)		$	1	$	4

II-165

NOTES (continued)
Alabama Power Company 2009 Annual Report

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in									Gain (Loss) Reclassified from Accumulated OCI into Income
Derivatives in Cash Flow	OCI on Derivative									(Effective Portion)
Hedging Relationships	(Effective Portion)										Amount
										Statements of Income
Derivative Category	2009			2008			2007			Location	2009			2008			2007
	(in millions)										(in millions)
Interest rate derivatives	$	(5	)	$	(11	)	$	(3	)	Interest expense	$	(12	)	$	(3	)	$	(1	)

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives not designated as hedging instruments were immaterial.

Contingent Features

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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2009, the fair value of derivative liabilities with contingent features was $7.6 million.

At December 31, 2009, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33.3 million.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participated in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2009 and 2008 are as follows:

					Net Income After
	Operating		Operating		Dividends on Preferred
Quarter Ended	Revenues		Income		and Preference Stock
	(in millions)
March 2009	$	1,340	$	299	$	146
June 2009		1,366		349		177
September 2009		1,592		483		261
December 2009		1,231		189		86
March 2008	$	1,337	$	274	$	130
June 2008		1,470		319		153
September 2008		1,865		478		252
December 2008		1,405		198		81

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

II-166

SELECTED FINANCIAL AND OPERATING DATA 2005-2009
Alabama Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands)	$	5,528,574	$	6,076,931	$	5,359,993	$	5,014,728	$	4,647,824
Net Income after Dividends on Preferred and Preference Stock (in thousands)	$	669,536	$	615,959	$	579,582	$	517,730	$	507,895
Cash Dividends on Common Stock (in thousands)	$	522,800	$	491,300	$	465,000	$	440,600	$	409,900
Return on Average Common Equity (percent)		13.27		13.30		13.73		13.23		13.72
Total Assets (in thousands)	$	17,524,093	$	16,536,006	$	15,746,625	$	14,655,290	$	13,689,907
Gross Property Additions (in thousands)	$	1,322,596	$	1,532,673	$	1,203,300	$	960,759	$	890,062
Capitalization (in thousands):
Common stock equity	$	5,236,461	$	4,854,310	$	4,410,683	$	4,032,287	$	3,792,726
Preference stock		343,373		343,412		343,466		147,361		—
Redeemable preferred stock		341,715		341,715		340,046		465,046		465,046
Long-term debt		6,082,489		5,604,791		4,750,196		4,148,185		3,869,465
Total (excluding amounts due within one year)	$	12,004,038	$	11,144,228	$	9,844,391	$	8,792,879	$	8,127,237
Capitalization Ratios (percent):
Common stock equity		43.6		43.6		44.8		45.9		46.7
Preference stock		2.9		3.1		3.5		1.7		—
Redeemable preferred stock		2.8		3.0		3.4		5.3		5.7
Long-term debt		50.7		50.3		48.3		47.1		47.6
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
First Mortgage Bonds —
Moody’s		—		—		—		—		A1
Standard and Poor’s		—		—		—		—		A+
Fitch		—		—		—		—	AA-
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		1,229,134		1,220,046		1,207,883		1,194,696		1,184,406
Commercial		198,642		211,119		216,830		214,723		212,546
Industrial		5,912		5,906		5,849		5,750		5,492
Other		780		775		772		766		759
Total		1,434,468		1,437,846		1,431,334		1,415,935		1,403,203
Employees (year-end)		6,842		6,997		6,980		6,796		6,621

II-167

SELECTED FINANCIAL AND OPERATING DATA 2005-2009 (continued)
Alabama Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands):
Residential	$	1,961,678	$	1,997,603	$	1,833,563	$	1,664,304	$	1,476,211
Commercial		1,429,601		1,459,466		1,313,642		1,172,436		1,062,341
Industrial		1,080,208		1,381,100		1,238,368		1,140,225		1,065,124
Other		25,594		24,112		21,383		18,766		17,745
Total retail		4,497,081		4,862,281		4,406,956		3,995,731		3,621,421
Wholesale — non-affiliates		619,859		711,903		627,047		634,552		551,408
Wholesale — affiliates		236,995		308,482		144,089		216,028		288,956
Total revenues from sales of electricity		5,353,935		5,882,666		5,178,092		4,846,311		4,461,785
Other revenues		174,639		194,265		181,901		168,417		186,039
Total		5,528,574	$	6,076,931	$	5,359,993	$	5,014,728	$	4,647,824
Kilowatt-Hour Sales (in thousands):
Residential		18,071,471		18,379,801		18,874,039		18,632,935		18,073,783
Commercial		14,185,622		14,551,495		14,761,243		14,355,091		14,061,650
Industrial		18,555,377		22,074,616		22,805,676		23,187,328		23,349,769
Other		217,594		201,283		200,874		199,445		198,715
Total retail		51,030,064		55,207,195		56,641,832		56,374,799		55,683,917
Wholesale — non-affiliates		14,316,742		15,203,960		15,769,485		15,978,465		15,442,728
Wholesale — affiliates		6,473,084		5,256,130		3,241,168		5,145,107		5,735,429
Total		71,819,890		75,667,285		75,652,485		77,498,371		76,862,074
Average Revenue Per Kilowatt-Hour (cents):
Residential		10.86		10.87		9.71		8.93		8.17
Commercial		10.08		10.03		8.90		8.17		7.55
Industrial		5.82		6.26		5.43		4.92		4.56
Total retail		8.81		8.81		7.78		7.09		6.50
Wholesale		4.12		4.99		4.06		4.03		3.97
Total sales		7.45		7.77		6.84		6.25		5.80
Residential Average Annual Kilowatt-Hour Use Per Customer		14,716		15,162		15,696		15,663		15,347
Residential Average Annual Revenue Per Customer	$	1,597	$	1,648	$	1,525	$	1,399	$	1,253
Plant Nameplate Capacity Ratings (year-end) (megawatts)		12,222		12,222		12,222		12,222		12,216
Maximum Peak-Hour Demand (megawatts):
Winter		10,701		10,747		10,144		10,309		9,812
Summer		10,870		11,518		12,211		11,744		11,162
Annual Load Factor (percent)		59.8		60.9		59.4		61.8		63.2
Plant Availability (percent):
Fossil-steam		88.5		90.1		88.2		89.6		90.5
Nuclear		93.3		94.1		87.5		93.3		92.9
Source of Energy Supply (percent):
Coal		53.4		58.5		60.9		60.2		59.5
Nuclear		18.6		17.8		16.5		17.4		17.2
Hydro		7.9		2.9		1.8		3.8		5.6
Gas		11.8		9.2		8.7		7.6		6.8
Purchased power —
From non-affiliates		2.0		2.9		1.8		2.1		3.8
From affiliates		6.3		8.7		10.3		8.9		7.1
Total		100.0		100.0		100.0		100.0		100.0

II-168

GEORGIA POWER COMPANY

FINANCIAL SECTION

II-169

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Georgia Power Company 2009 Annual Report

The management of Georgia Power Company (the “Company”) 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 the 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. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

/s/ Michael D. Garrett

Michael D. Garrett
President and Chief Executive Officer

/s/ Ronnie R. Labrato

Ronnie R. Labrato
Executive Vice President, Chief Financial Officer, and Treasurer

February 25, 2010

II-170

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, 2009 and 2008, 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, 2009. 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 financial statements (pages II-196 to II-241) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2009 and 2008 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

II-171

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power Company 2009 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 business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. The Company is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. On August 27, 2009, the Georgia Public Service Commission (PSC) approved an accounting order that allows the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations over the 18-month period ending December 31, 2010 in lieu of filing a request for a base rate increase. The Company is required to file a general base rate case by July 1, 2010. The Company filed for an adjustment to its fuel cost recovery rate on December 15, 2009. On February 22, 2010, the Company, the Georgia PSC Public Interest Advocacy Staff, and three customer groups entered into a stipulation to resolve the case, subject to approval by the Georgia PSC. A final decision by the Georgia PSC is expected on March 11, 2010. If approved, the new fuel cost recovery rates will go into effect on April 1, 2010.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective 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 after dividends on preferred and preference stock. 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 and nuclear 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. The 2009 fossil/hydro Peak Season EFOR of 1.43% was better than the target. The 2009 nuclear Peak Season EFOR of 3.70% was above the target due to an unplanned outage at Plant Hatch. 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 2009 performance was better than the target for these reliability measures.

Net income after dividends on preferred and preference stock is the primary measure of the Company’s financial performance. The Company’s 2009 results compared to its targets for some of these key indicators are reflected in the following chart:

	2009	2009
	Target	Actual
Key Performance Indicator	Performance	Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile in customer surveys
Peak Season EFOR — fossil/hydro	2.75% or less		1.43	%
Peak Season EFOR — nuclear	2.75% or less		3.70	%
Net Income	$856 million	$814 million

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The Company’s net income target for 2009 was set lower than in the prior year to reflect the economic downturn that began in late 2008; however, the global recession’s impacts on energy demand were greater than anticipated. As the recession escalated, management emphasized stringent cost-containment efforts to partially offset the resulting revenue declines and, in lieu of a rate increase, worked with the Georgia PSC to develop the accounting order discussed previously. Although the Company did not meet its target, these efforts provided substantial improvement in the Company’s financial condition while consistently demonstrating the Company’s commitment to customer service, reliability, and competitive prices.

II-172

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

Earnings

The Company’s 2009 net income after dividends on preferred and preference stock totaled $814 million representing an $88.9 million, or 9.8%, decrease from 2008. The decrease was primarily related to lower commercial and industrial base revenues resulting from the recessionary economy and decreased revenues from market-response rates to large commercial and industrial customers that were partially offset by cost containment activities, increased recognition of environmental compliance cost recovery revenues, and the amortization of the regulatory liability related to other cost of removal activities as authorized by the Georgia PSC. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Rate Plans” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Rate Plans” for additional information. The Company’s 2008 net income after dividends on preferred and preference stock totaled $903 million representing a $66.8 million, or 8.0%, increase over 2007. The increase was primarily related to increased contributions from market-response rates for large commercial and industrial customers, higher retail base revenues resulting from the retail rate increase effective January 1, 2008 (2007 Retail Rate Plan), and increased allowance for equity funds used during construction. These increases were partially offset by increased depreciation and amortization resulting from more plant in service and changes to depreciation rates. The Company’s 2007 earnings totaled $836 million representing a $48.9 million, or 6.2%, increase over 2006. Operating income increased slightly in 2007 primarily due to increased operating revenues from transmission and outdoor lighting and decreased property taxes, partially offset by higher non-fuel operating expenses. Net income increased primarily due to higher allowance for equity funds used during construction and lower income tax expenses resulting from the Company’s donation of Tallulah Gorge to the State of Georgia, partially offset by higher financing costs.

RESULTS OF OPERATIONS

A condensed income statement for the Company follows:

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008		2007
	(in millions)
Operating revenues	$	7,692		$	(720	)	$	840	$	326
Fuel		2,717			(95	)		172		408
Purchased power		979			(426	)		355		(95	)
Other operations and maintenance		1,494			(87	)		19		1
Depreciation and amortization		655			18			126		13
Taxes other than income taxes		317			—			25		(8	)
Total operating expenses		6,162			(590	)		697		319
Operating income		1,530			(130	)		143		7
Total other income and (expense)		(289	)		(37	)		5		18
Income taxes		410			(78	)		70		(25	)
Net income		831			(89	)		78		50
Dividends on preferred and preference stock		17			—			11		1
Net income after dividends on preferred and preference stock	$	814		$	(89	)	$	67	$	49

II-173

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

Operating Revenues

Operating revenues in 2009, 2008, and 2007 and the percent of change from the prior year were as follows:

	Amount
	2009			2008			2007
	(in millions)
Retail — prior year	$	7,287		$	6,498		$	6,206
Estimated change in —
Rates and pricing		(64	)		397			(66	)
Sales growth (decline)		(93	)		(21	)		46
Weather		(6	)		(37	)		18
Fuel cost recovery		(212	)		450			294
Retail — current year		6,912			7,287			6,498
Wholesale revenues —
Non-affiliates		395			569			538
Affiliates		112			286			278
Total wholesale revenues		507			855			816
Other operating revenues		273			270			258
Total operating revenues	$	7,692		$	8,412		$	7,572
Percent change		(8.6	)%		11.1	%		4.5	%

Retail base revenues of $3.9 billion in 2009 decreased by $161.8 million, or 3.9%, from 2008 primarily due to lower industrial and commercial base revenues resulting from the recessionary economy and decreased revenues from market-response rates to large commercial and industrial customers. Industrial base revenues decreased $207.1 million, or 27.9%, and commercial base revenues decreased $35.8 million, or 2.1%. These decreases were partially offset by an increase in residential base revenues of $78.4 million, or 4.8%. All customer classes were positively affected by increased recognition of environmental compliance cost recovery revenues. Retail base revenues of $4.1 billion in 2008 increased by $338.3 million, or 9.0%, from 2007 primarily due to an increase in revenues from market-response rates to large commercial and industrial customers, the retail rate increase effective January 1, 2008, and a 0.7% increase in retail customers. The increase was partially offset by a weak economy in the Southeast and less favorable weather impacts in 2008 than in 2007. Retail base revenues were $3.8 billion in 2007. There was not a material change in total retail base revenues compared to 2006, although industrial base revenues decreased $56.5 million, or 8.5%, primarily due to lower sales and a lower contribution from market-response rates for large commercial and industrial customers. This decrease was partially offset by a $31.8 million, or 2.1%, increase in residential base revenues as well as a $22.6 million, or 1.5%, increase in commercial base revenues primarily due to higher sales from favorable weather and customer growth of 1.2%. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information.

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Georgia Power Company 2009 Annual Report

Wholesale revenues from sales to non-affiliated utilities were as follows:

	2009		2008		2007
	(in millions)
Unit power sales —
Capacity	$	43	$	40		$	33
Energy		26		44			33
Total		69		84			66
Other power sales —
Capacity and other		140		129			158
Energy		186		356			314
Total		326		485			472
Total non-affiliated	$	395	$	569		$	538

Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.

Revenues from unit power sales decreased $15.9 million, or 18.9%, in 2009 primarily due to a 26.0% decrease in kilowatt-hour (KWH) energy sales due to the recessionary economy and generally unfavorable weather. Revenues from unit power sales increased $18.2 million, or 27.4%, in 2008 driven by higher fuel rates and an 8.2% increase in the KWH energy sales primarily related to sales by the Company’s generating units when other Southern Company system units were unavailable. Revenues from unit power sales remained relatively constant in 2007. Revenues from other non-affiliated sales decreased by $158.3 million, or 32.7%, in 2009, increased $12.7 million, or 2.7%, in 2008, and decreased $9.6 million, or 2.0%, in 2007. The decrease in 2009 was due to lower natural gas prices and a 49.7% decrease in KWH sales due to the recessionary economy and generally unfavorable weather. The increase in 2008 was primarily driven by the fuel component within non-affiliate wholesale prices which has increased with the effects of higher fuel and purchased power costs. This increase was partially offset by a 9.8% decrease in KWH energy sales and decreased contributions from the emissions allowance component of market-based wholesale rates. The decrease in 2007 was primarily due to a decrease in revenues from large territorial contracts resulting from lower emissions allowance prices.

Wholesale revenues from sales to affiliated companies within the Southern Company system 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 2009, wholesale revenues from sales to affiliates decreased 60.9% due to lower natural gas prices and a 32.2% decrease in KWH sales due to the recessionary economy and generally unfavorable weather. In 2008, KWH energy sales to affiliated companies decreased 28.8% while revenues from sales to affiliates increased 3.0%. In 2007, KWH energy sales to affiliates decreased 5.0% while revenues from sales to affiliates increased 10.0%. The revenue increases in 2008 and 2007 were primarily due to the increased cost of fuel and other marginal generation components of the rates. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other operating revenues remained relatively flat in 2009. Other operating revenues increased $12.3 million, or 4.8%, in 2008 primarily due to a $6.7 million increase in revenues from outdoor lighting resulting from a 15.8% increase in lighting customers and a $7.6 million increase in customer fees resulting from higher rates that went into effect in 2008, partially offset by a $2.2 million decrease in equipment rentals revenue. Other operating revenues increased $22.2 million, or 9.4%, in 2007 primarily due to an $11.6 million increase in transmission revenues due to the increased usage of the Company’s transmission system by non-affiliated companies, a $7.9 million increase in revenues from outdoor lighting activities due to a 10% increase in the number of lighting customers, and a $4.0 million increase from customer fees.

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Georgia Power Company 2009 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in volume of energy sold from year to year. KWH sales for 2009 and the percent change by year were as follows:

	KWH		Percent Change
	2009		2009			2008			2007
	(in billions)
Residential		26.3		(0.5	)%		(1.6	)%		2.4	%
Commercial		32.6		(1.4	)		0.0			2.9
Industrial		21.8		(9.7	)		(5.2	)		(0.3	)
Other		0.7		0.1			(3.8	)		5.6
Total retail		81.4		(3.5	)		(2.1	)		1.8
Wholesale
Non-affiliates		5.2		(46.6	)		(7.8	)		(1.0	)
Affiliates		2.5		(32.2	)		(28.8	)		(5.0	)
Total wholesale		7.7		(42.7	)		(14.7	)		(2.3	)
Total energy sales		89.1		(8.9	)%		(4.0	)%		1.1	%

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers.

Residential KWH sales decreased 0.5% in 2009 compared to 2008 primarily due to slightly less favorable weather, partially offset by an increase of 0.2% in residential customers. Commercial and industrial KWH sales decreased 1.4% and 9.7%, respectively, in 2009 compared to 2008 due to the recessionary economy. During 2009, there was a broad decline in demand across all industrial segments, most significantly in the chemical, primary metals, textiles, and stone, clay, and glass sectors.

Residential KWH sales decreased 1.6% in 2008 compared to 2007 primarily due to less favorable weather, partially offset by a 0.7% increase in residential customers. Commercial KWH sales remained flat in 2008 compared to 2007 despite a 0.2% increase in commercial customers. Industrial KWH sales decreased 5.2% in 2008 over 2007 primarily due to reduced demand and closures within the textile and primary and fabricated metal industries, which were a result of the slowing economy that worsened during the fourth quarter 2008.

Residential KWH sales increased 2.4% in 2007 over 2006 due to favorable weather and a 1.3% increase in residential customers. Commercial KWH sales increased 2.9% in 2007 over 2006 primarily due to favorable weather and a 0.3% increase in commercial customers. Industrial KWH sales decreased 0.3% primarily due to reduced demand and closures within the textile industry; however, this was partially offset by a 2.9% increase in the number of industrial customers.

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Georgia Power Company 2009 Annual Report

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 generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows:

	2009		2008		2007
Total generation(billions of KWHs)		72.4		80.8		87.0
Total purchased power(billions of KWHs)		20.4		21.3		18.9
Sources of generation(percent) -
Coal		67		74		75
Nuclear		21		19		18
Gas		10		6		7
Hydro		2		1		—
Cost of fuel, generated(cents per net KWH) -
Coal		4.12		3.44		2.87
Nuclear		0.55		0.51		0.51
Gas		5.30		6.90		6.28
Average cost of fuel, generated(cents per net KWH)*		3.48		3.11		2.68
Average cost of purchased power(cents per net KWH)		6.06		8.10		7.27

* Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

Fuel and purchased power expenses were $3.7 billion in 2009, a decrease of $521.7 million, or 12.4%, below prior year costs. This decrease was due to a $371.2 million decrease related to fewer KWHs generated and purchased primarily due to lower customer demand as a result of the recessionary economy and a $150.5 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.

Fuel and purchased power expenses were $4.2 billion in 2008, an increase of $526.6 million, or 14.3%, above prior year costs. Substantially all of this increase was due to the higher average cost of fuel and purchased power.

Fuel and purchased power expenses were $3.7 billion in 2007, an increase of $312.9 million, or 9.3%, above prior year costs. This increase was driven by a $414.5 million increase in total energy costs due to the higher average cost of fuel and purchased power, partially offset by a $101.6 million reduction due to fewer KWHs purchased.

Coal prices continued to be influenced by worldwide demand from developing countries, as well as increased mining and fuel transportation costs. While coal prices reached unprecedented high levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices did not fully offset the higher priced coal already in inventory and under long-term contract. Demand for natural gas in the United States also was affected by the recessionary economy leading to significantly lower natural gas prices. During 2009, uranium prices continued to moderate from the highs set during 2007. Worldwide production levels increased in 2009; however, secondary supplies and inventories were still required to meet worldwide reactor demand.

Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. 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 2009 Annual Report

Other Operations and Maintenance Expenses

In 2009, other operations and maintenance expenses decreased $86.7 million, or 5.5%, compared to 2008. The decrease was due to a $46.1 million decrease in power generation, a $28.0 million decrease in transmission and distribution, and a $31.5 million decrease in customer accounting, service, and sales, most of which are related to cost containment activities in an effort to offset the effects of the recessionary economy.

In 2008, other operations and maintenance expenses increased $19.2 million, or 1.2%, compared to 2007. The increase was primarily the result of a $14.7 million increase in the accrual for property damage approved under the 2007 Retail Rate Plan, a $14.6 million increase in scheduled outages and maintenance for fossil generating plants, and a $22.0 million increase related to meter reading, records and collections, and uncollectible account expenses. These increases were partially offset by decreases of $24.7 million related to the timing of transmission and distribution operations and maintenance and $7.4 million related to medical, pension, and other employee benefits. In 2007, the change in other operations and maintenance expenses was immaterial compared to 2006.

Depreciation and Amortization

Depreciation and amortization increased $18.2 million, or 2.9%, in 2009 compared to the prior year primarily due to additional plant in service related to transmission, distribution, and environmental projects, partially offset by the amortization of $41.4 million of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Rate Plans” herein, Note 1 to the financial statements under “Depreciation and Amortization,” and Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.

Depreciation and amortization increased $125.8 million, or 24.6%, in 2008 compared to the prior year primarily due to an increase in plant in service related to completed transmission, distribution, and environmental projects, changes in depreciation rates effective January 1, 2008 approved under the 2007 Retail Rate Plan, and the expiration of amortization related to a regulatory liability for purchased power costs under the terms of the retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan).

Depreciation and amortization increased $12.4 million, or 2.5%, in 2007 compared to the prior year primarily due to a 3.4% increase in plant in service related to transmission, distribution, and environmental projects from the prior year. This increase was partially offset by a decrease in amortization of the regulatory liability for purchased power costs as described above.

Taxes Other Than Income Taxes

In 2009, the increase in taxes other than income taxes was immaterial. In 2008, taxes other than income taxes increased $25.1 million, or 8.6%, from the prior year primarily due to higher municipal franchise fees resulting from retail revenue increases during 2008. Taxes other than income taxes decreased $7.7 million, or 2.6%, in 2007 primarily due to the resolution of a dispute regarding property taxes in Monroe County, Georgia.

Allowance for Funds Used During Construction Equity

In 2009, the increase in allowance for funds used during construction (AFUDC) equity was immaterial. AFUDC equity increased $27.1 million, or 39.8%, in 2008 and $36.7 million, or 116.3%, in 2007 primarily due to the increase in construction work in progress balances related to ongoing environmental and transmission projects, as well as three combined cycle generating units at Plant McDonough.

Interest Expense, Net of Amounts Capitalized

In 2009, interest expense, net of amounts capitalized increased $40.5 million, or 11.7%, primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes and pollution control bonds to fund the Company’s ongoing construction program. The increase in interest expense in 2008 was immaterial. Interest expense increased $25.5 million, or 8.0%, in 2007 primarily due to a 13.9% increase in long-term debt levels due to the issuance of additional senior notes and pollution control revenue bonds.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

Other Income (Expense), Net

Other income (expense), net increased $7.5 million, or 80.8%, in 2009 primarily related to $2.0 million and $0.9 million increases in customer contracting and income resulting from purchases by large commercial and industrial customers of hedges against market-response rates, respectively, and a decrease of $2.4 million in donations. Other income (expense), net decreased $24.0 million, or 163.0%, in 2008 primarily due to a $12.9 million change in classification of revenues related to a residential pricing program to base retail revenues in 2008 as ordered by the Georgia PSC under the 2007 Retail Rate Plan, as well as decreased revenues of $7.3 million and $2.6 million related to non-operating rental income and customer contracting, respectively. Other income (expense), net increased $5.8 million, or 66.5%, in 2007 primarily due to $4.0 million from land and timber sales.

Income Taxes

Income taxes decreased $77.5 million, or 15.9%, in 2009 primarily due to lower pre-tax income. Income taxes increased $70.0 million, or 16.8%, in 2008 primarily due to increased pre-tax net income and the 2007 Tallulah Gorge donation. This increase was partially offset by an increase in AFUDC equity, which is non-taxable, as well as additional state tax credits and an increase in the federal production activities deduction. Income taxes decreased $24.8 million, or 5.6%, in 2007 primarily due to state and federal deductions for the Company’s donation of 2,200 acres in the Tallulah Gorge area to the State of Georgia and higher federal manufacturing deductions.

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial.

FUTURE EARNINGS POTENTIAL

General

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. 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 wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and revenues 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 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 Company’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining 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 or decline in the Company’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery will impact future earnings.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. Under the 2007 Retail Rate Plan, an environmental compliance cost recovery (ECCR) tariff was implemented on January 1, 2008 to allow for the recovery of most of the costs related to environmental controls mandated by state and federal regulation scheduled for completion between 2008 and 2010. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.

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Georgia Power Company 2009 Annual Report

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 the Company, 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. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 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 or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the

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Georgia Power Company 2009 Annual Report

defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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; the Endangered Species Act; and related federal and state regulations. 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 2009, the Company had invested approximately $3.5 billion in capital projects to comply with these requirements, with annual totals of $440 million, $689 million, and $856 million for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to ensure compliance with existing and new statutes and regulations will be an additional $259 million, $350 million, and $600 million for 2010, 2011, and 2012, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, 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 2009, the Company had spent approximately $3.2 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality standard. A 20-county area within metropolitan Atlanta is the only location within the Company’s service area that is currently designated as nonattainment for the standard, which could require additional reductions in NO_x emissions from power plants. In March 2008, however, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to finalize the revised standard in August 2010 and require state implementation plans for any nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory.

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Georgia Power Company 2009 Annual Report

During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within the Company’s service area. State plans for addressing the nonattainment designations for this standard could require further reductions in SO₂ and NO_x emissions from power plants.

On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard for SO₂. The EPA is expected to finalize the revised SO₂ standard in June 2010.

Twenty-eight eastern states, including the State of Georgia, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The State of Georgia has completed its plan to implement CAIR, and emissions reductions are being accomplished by the installation of emissions controls at certain of the Company’s coal-fired facilities and/or by the purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in July 2010.

The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring 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) to certain sources built between 1962 and 1977, and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural conditions goal by 2018 and for each ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and NO_x, and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. The State of Georgia is currently completing its implementation plan for BART compliance and other measures required to achieve the first phase of reasonable progress.

The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants, including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and trade program for the reduction of mercury emissions from coal-fired power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.

In February 2004, the EPA finalized the Industrial Boiler (IB) MACT rule, which imposed limits on hazardous air pollutants from industrial boilers, including biomass boilers. Compliance with the final rule was scheduled to begin in September 2007; however, in response to challenges to the final rule, the U.S. Court of Appeals for the District of Columbia Circuit vacated the IB MACT rule in its entirety in July 2007 and ordered the EPA to develop a new IB MACT rule. In September 2009, the deadline to promulgate a proposed rule was extended from July 15, 2009 to April 15, 2010, with a final rule required by December 16, 2010. The EPA is currently developing the new rule and may change the methodology to determine the MACT limits for industrial boilers.

The impacts of the eight-hour ozone standards, the fine particulate matter nonattainment designations, and future revisions to CAIR, the SO2 standard, the Clean Air Visibility Rule, and the MACT rules for electric generating units and industrial boilers on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. As a result of these uncertainties, the Company has delayed any further construction activities related to both the installation of emissions control equipment at Plants Branch and Yates and the conversion of Plant Mitchell from coal-fired to biomass-fired.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company has already installed a number of SO₂and NO_x emissions controls and plans to install additional controls within the next several years to ensure continued compliance with applicable air quality requirements. In addition, most units in Georgia are required to install specific emissions controls according to a schedule set forth in the state’s Multipollutant Rule, which is designed to reduce emissions of SO₂, NO_x, and mercury in Georgia.

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Water Quality

In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is now in the process of revising the regulations. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on further rulemaking by the EPA and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

On December 28, 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions by 2013. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain of the Company’s facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, 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 releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters – Environmental Remediation” for additional information.

Coal Combustion Byproducts

The EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA has collected information from the electric utility industry on surface impoundment safety and conducted on-site inspections at two facilities of the Company as part of its evaluation. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010. The impact of these additional regulations on the Company will depend on the specific provisions of the final rule and cannot be determined at this time. However, additional regulations of coal combustion byproducts could have a significant impact on the Company’s management, beneficial use, and disposal of such byproducts and could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. As a result of these uncertainties, the Company has delayed any further construction activities related to both the installation of emissions control equipment at Plants Branch and Yates and the conversion of Plant Mitchell from coal-fired to biomass-fired.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

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In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 — BUSINESS — “Rate Matters — Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 57  million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 48 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company is actively constructing new generating facilities with lower greenhouse gas emissions. These include two additional nuclear generating units at Plant Vogtle and three combined cycle units at Plant McDonough.

The Company has also proposed the conversion of Plant Mitchell from coal-fired to biomass generation and is currently evaluating the costs and viability of other renewable technologies for the State of Georgia. On February 2, 2010, the Georgia PSC approved the Company’s request to delay construction activities related to Plant Mitchell pending the EPA’s anticipated issuance of regulations associated with coal combustion byproducts and the IB MACT rule described previously.

PSC Matters

Rate Plans

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through 2010. Under the 2007 Retail Rate Plan, the Company’s earnings are evaluated against a retail return on common equity (ROE) range of 10.25% to 12.25%. Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs related to environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008.

In connection with the 2007 Retail Rate Plan, the Company agreed that it would not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. The economic recession has significantly reduced the Company’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, the Company’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as

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allowed under the 2007 Retail Rate Plan, on June 29, 2009, the Company filed a request with the Georgia PSC for an accounting order that would allow the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations.

On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, the Company was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail ROE. For the year ended December 31, 2009, the Company amortized $41 million of the regulatory liability. In addition, the Company may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. The Company is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under “Retail Regulatory Matters — Rate Plans” for additional information.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved increases in the Company’s total annual billings of approximately $383 million effective March 1, 2007 and approximately $222 million effective June 1, 2008.

On December 15, 2009, the Company filed for a fuel cost recovery increase with the Georgia PSC. On February 22, 2010, the Company, the Georgia PSC Public Interest Advocacy Staff, and three customer groups entered into a stipulation to resolve the case, subject to approval by the Georgia PSC (the Stipulation). Under the terms of the Stipulation, the Company’s annual fuel cost recovery billings will increase by approximately $425 million. In addition, the Company will implement an interim fuel rider, which would allow the Company to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more than $75 million. The Company is required to file its next fuel case by March 1, 2011. The Georgia PSC is scheduled to vote on the Stipulation on March 11, 2010 with the new fuel rates to become effective April 1, 2010. The ultimate outcome of this matter cannot be determined at this time.

As of December 31, 2009, the Company’s under recovered fuel balance totaled approximately $665 million, which if the Stipulation is approved, the Company will recover over 32 months beginning April 1, 2010. Therefore, approximately $373 million of the under recovered regulatory clause revenues for the Company is included in deferred charges and other assets at December 31, 2009.

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, a change in the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters — Fuel Cost Recovery” for additional information.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of the Company. The Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be $112 million. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of the Company.

On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $51 million is available to the Company, under the ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. The Company continues to assess the other financial implications of the ARRA.

The U.S. House of Representatives and the U.S. Senate have passed separate bills related to healthcare reform. Both bills include a provision that would make Medicare Part D subsidy reimbursements taxable. If enacted into law, this provision could have a significant negative impact on the Company’s net income. See Note 2 to the financial statements under “Other Postretirement Benefits” for additional information.

The ultimate impact of these matters cannot be determined at this time.

Income Tax Matters

Georgia State Income Tax Credits

The Company’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of

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Revenue (DOR) has not responded to these claims. In July 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information. If the Company prevails, these claims could have a significant, and possibly material, positive effect on the Company’s net income. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company’s cash flow. The ultimate outcome of this matter cannot now be determined.

Internal Revenue Code Section 199 Domestic Production Deduction

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Construction

Nuclear

On August 26, 2009, the Nuclear Regulatory Commission (NRC) issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of the Company, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). See Note 4 to the financial statements for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively.

In April 2008, the Company, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including certain index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. The Company’s proportionate share is 45.7%.

On February 23, 2010, the Company, acting for itself and as agent for the Owners, and the Consortium entered into an amendment to the Vogtle 3 and 4 Agreement. The amendment, which is subject to the approval of the Georgia PSC, replaces certain of the index-based adjustments to the purchase price with fixed escalation amounts.

The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement.

The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

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Georgia Power Company 2009 Annual Report

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve the inclusion of the related construction work in progress accounts in rate base.

On April 21, 2009 the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow the Company to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective on January 1, 2011. With respect to Plant Vogtle Units 3 and 4, this legislation allows the Company to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion.

On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. The Company believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions.

On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. The Company is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3
and 4.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds.

On August 31, 2009, the Company filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any proposed change to the estimated construction cost as certified by the Georgia PSC in March 2009. On February 25, 2010, the Georgia PSC approved the expenditures made by the Company pursuant to the certification through June 30, 2009. The Georgia PSC also ordered that in its future semi-annual construction monitoring reports, the Company will report against a total certified cost of approximately $6.1 billion, which is the effective certified amount after giving effect to the Georgia Nuclear Energy Financing Act as described above. The Company will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

The ultimate outcome of these matters cannot be determined at this time.

Other Construction

On August 10, 2009, the Company filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. On September 30, 2009, the Company amended the report. As amended, the report includes a request for an increase in the certified costs to construct Plant McDonough. The Georgia PSC held a hearing in December 2009 and is scheduled to render its decision on March 16, 2010. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

The Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

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Georgia Power Company 2009 Annual Report

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following 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 accounting standards which require 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 the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines 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, in accordance with generally accepted accounting principles (GAAP), records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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, coal combustion byproducts, including coal ash, and other environmental matters.

• Changes in existing income tax regulations or changes in IRS or Georgia DOR 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 new or existing matters through the legislative process, the court systems, the IRS, the Georgia DOR, the FERC, or the EPA.

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Georgia Power Company 2009 Annual Report

Unbilled Revenues

Revenues related to the retail 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.

Pension and Other Postretirement Benefits

The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that considers external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption would result in an $8 million or less change in total benefit expense and a $104 million or less change in projected obligations.

New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted this new guidance effective January 1, 2010, with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2009. Throughout the turmoil in the financial markets, the Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit increased in 2009, and the Company may continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees for the Company average less than ³/ ₈ of 1% per year. See “Sources of Capital” and “Financing Activities” herein for additional information.

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Georgia Power Company 2009 Annual Report

The Company’s investments in pension and nuclear decommissioning trust funds remained stable in value as of December 31, 2009. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future fund performance and cannot be determined at this time. Any changes to funding obligations to the nuclear decommissioning trusts will be determined in connection with the Company’s 2010 retail rate case and are not currently expected to be material.

Cash flow from operations totaled $1.4 billion in 2009, a decrease of $310 million from 2008, primarily due to an $89 million decrease in net income, a reduction in deferred revenues of approximately $172 million, a reduction in accrued compensation of approximately $122 million, and an increase in fuel inventory additions of approximately $150 million, partially offset by a reduction in accounts receivable of approximately $210 million. Cash flow from operations totaled $1.7 billion in 2008, an increase of $279 million from 2007, primarily due to higher retail operating revenues partially offset by higher inventory additions. Cash flow from operations in 2007 totaled $1.4 billion, an increase of $249 million from 2006, primarily due to higher retail revenues primarily related to higher fuel cost recovery revenues and less cash used for working capital primarily from lower inventory additions and increases in other current liabilities.

Net cash used for investing activities totaled $2.4 billion, $1.9 billion, and $1.9 billion in 2009, 2008, and 2007, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of generation, transmission, and distribution facilities; and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, capital contributions from Southern Company, and the issuance of debt and preference stock.

Cash provided from financing activities totaled $881 million, $310 million, and $430 million for 2009, 2008, and 2007, respectively. These totals are primarily related to additional issuances of senior notes in all years. The statements of cash flows provide additional details. See “Financing Activities” herein.

Significant balance sheet changes in 2009 include the $1.9 billion increase in total property, plant, and equipment discussed above. Other significant balance sheet changes in 2009 include a $776 million increase in long-term debt to provide funds for the Company’s continuous construction program. Significant balance sheet changes in 2008 include a $1.1 billion increase in long-term debt primarily to replace short-term debt and provide funds for the Company’s continuous construction program and an increase in total property, plant, and equipment of $1.3 billion. Other significant balance sheet changes in 2008 include a decrease of $1.0 billion in prepaid pension costs, an increase of $908 million in other regulatory assets, and a decrease of $462 million in other regulatory liabilities primarily attributable to the decline in market value of the Company’s pension trust fund.

The Company’s ratio of common equity to total capitalization, including short-term debt, was 47.8% in 2009, 46.5% in 2008, and 47.5% in 2007. The Company has received investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock. See “Credit Rating Risk” herein and SELECTED FINANCIAL AND OPERATING DATA for additional information regarding the Company’s security ratings.

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, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approvals, and other factors. In addition, on February 16, 2010, the U.S. Department of Energy (DOE) offered the Company a conditional commitment for federal loan guarantees that would apply to future Company borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to the Company and would be secured by a first priority lien on the Company’s ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. The Company has 90 days to accept the conditional commitment, including obtaining any necessary regulatory approvals. The Company will work with the DOE to finalize the loan guarantees. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the COL for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for the Company. See FUTURE EARNINGS POTENTIAL — “Construction — Nuclear” herein and Note 3 to the financial statements under “Nuclear Construction” for more information on Plant Vogtle Units 3 and 4.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

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. 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, as amended. The amounts of securities authorized by the Georgia PSC and 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. 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 for under recovered fuel costs and to meet cash needs which can fluctuate significantly due to the seasonality of the business.

To meet short-term cash needs and contingencies, at December 31, 2009 the Company had credit arrangements with banks totaling $1.7 billion. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. In addition, the Company has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs.

At December 31, 2009, bank credit arrangements were as follows:

			Expires
Total	Unused		2010		2012
	(in millions)
$1,715	$	1,703	$	595	$	1,120

Of the credit arrangements that expire in 2010, $40 million allow for the execution of term loans for an additional two-year period.

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from issuances for the benefit 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, 2009, the Company had $324 million of outstanding commercial paper.

Financing Activities

In February 2009, the Company issued $500 million aggregate principal amount of Series 2009A 5.95% Senior Notes due February 1, 2039. In December 2009, the Company issued $500 million aggregate principal amount of Series 2009B 4.25% Senior Notes due December 1, 2019. The net proceeds from the sale of these senior notes were used by the Company to repay at maturity $150 million aggregate principal amount of its Series U Floating Rate Senior Notes and $125 million aggregate principal amount of its Series V 4.10% Senior Notes, to redeem $55 million aggregate principal amount of its Series D 5.50% Senior Notes, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including the Company’s continuous construction program.

The Company also incurred $416.5 million of obligations related to the issuance of pollution control revenue bonds, the proceeds of which were used to retire $327.3 million of pollution control revenue bonds and to finance the construction of certain solid waste disposal facilities.

During 2009, the Company settled interest rate hedges of $300 million related to the issuance of senior notes at a loss of $19 million. The effective portion of these losses has been deferred in other comprehensive income and is being amortized to interest expense over the life of the original interest rate hedge.

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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation facilities. At December 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $32 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 totaled approximately $1.2 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

On September 2, 2009, Moody’s Investors Service (Moody’s) affirmed the credit ratings of the Company’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On September 4, 2009, Fitch Ratings, Inc. affirmed the Company’s senior unsecured notes and commercial paper ratings of A+/F1, respectively, but revised the Company’s rating outlook to negative. On October 6, 2009, Standard and Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc. (S&P) affirmed the credit ratings of the Company’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook.

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,where possible, 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. The Company’s 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 enters into forward starting interest rate swaps and other derivatives that have been designated as hedges. These derivatives have a notional amount of $300 million and are related to certain variable rate debt over the next year. The weighted average interest rate on $1.2 billion of outstanding variable rate long-term debt that has not been hedged at January 1, 2010 was 0.23%. 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 $12 million at January 1, 2010. See Notes 1 and 11 to the financial statements under “Financial Instruments” and “Interest Rate Derivatives,” respectively, for additional information.

To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for gas purchases.

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

	2009			2008
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(113	)	$	—
Contracts realized or settled		150			(69	)
Current period changes(a)		(112	)		(44	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(75	)	$	(113	)

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

The change in the fair value positions of the energy-related derivative contracts for the year-ended December 31, 2009 was an increase of $38.2 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and the price of natural gas. At December 31, 2009, the Company had a net hedge volume of 70.7 million mmBtu with a weighted average contract cost approximately $1.08 per mmBtu above market prices, and 59.3 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.96 per mmBtu above market prices. Substantially all natural gas hedges gains and losses are recovered through the Company’s fuel cost recovery mechanism.

At December 31, 2009 and 2008, all of the Company’s energy-related derivative contracts were designated as regulatory hedges related to the Company’s fuel hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2 & 3			Years 4 & 5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(75	)		(47	)		(27	)		(1	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(75	)	$	(47	)	$	(27	)	$	(1	)

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial statements for further discussion on fair value measurement.

The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P 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 Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $2.5 billion for 2010, $2.4 billion for 2011, and $2.8 billion for 2012. Environmental expenditures included in these estimated amounts are $259 million, $350 million, and $600 million for 2010, 2011, and 2012, respectively. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 and Note 7 to the financial statements under “Construction – Nuclear” and “Construction Program,” respectively, for additional information.

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.”

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 the related interest, preferred and preference stock dividends, leases, derivative obligations, and other purchase commitments are as follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(d)		Total
	(in millions)
Long-term debt(a) —
Principal	$	250	$	611	$	525	$	6,597	$	—	$	7,983
Interest		378		736		670		6,067		—		7,851
Preferred and preference stock dividends(b)		17		35		35		—		—		87
Energy-related derivative obligations(c)		47		27		1		—		—		75
Operating leases		37		54		28		17		—		136
Capital leases		4		9		10		40		—		63
Unrecognized tax benefits and interest(d)		183		—		—		—		18		201
Purchase commitments(e)—
Capital(f)		2,298		4,984		—		—		—		7,282
Limestone(g)		19		30		32		20		—		101
Coal		2,239		2,609		959		1,533		—		7,340
Nuclear fuel		198		224		171		207		—		800
Natural gas(h)		473		1,028		772		3,414		—		5,687
Purchased power		343		583		472		1,939		—		3,337
Long-term service agreements(i)		14		61		91		550		—		716
Trusts —
Nuclear decommissioning(j)		3		7		7		53		—		70
Postretirement benefits(k)		31		53		—		—		—		84
Total	$	6,534	$	11,051	$	3,773	$	20,437	$	18	$	41,813

(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, 2010, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Excludes capital lease amounts (shown separately).
(b)	Preferred and preference stock does not mature; therefore, amounts provided are for the next five years only.
(c)	For additional information see Notes 1 and 11 to the financial statements.
(d)	The timing related to the realization of $18 million in unrecognized tax benefits and corresponding interest payments cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. Of the total $201 million, $97 million is the estimated cash payment. See Note 3 under “Income Tax Matters” and Note 5 under “Unrecognized Tax Benefits” to the financial statements for additional information.
(e)	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, $1.6 billion, and $1.6 billion, respectively.
(f)	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 nuclear fuel. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program.
(g)	As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment.
(h)	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, 2009.
(i)	Long-term service agreements include price escalation based on inflation indices.
(j)	Projections of nuclear decommissioning trust contributions are based on the 2007 Retail Rate Plan and are subject to change in the 2010 retail rate case.
(k)	The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Therefore, no amounts related to the pension trust fund are included in the table. 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 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, fuel cost recovery and other rate actions, environmental regulations and expenditures, the Company’s projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, access to sources of capital, the impacts of the adoption of new accounting rules, impacts of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, start and 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances, and also changes in 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 recovery from the recent recession, population, business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of the Company’s employee benefit plans and nuclear decommissioning trusts;

• 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 and other cost recovery mechanisms;

• regulatory approvals and actions related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

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

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

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STATEMENTS OF INCOME

For the Years Ended December 31, 2009, 2008, and 2007
Georgia Power Company 2009 Annual Report

	2009			2008			2007
				(in thousands)
Operating Revenues:
Retail revenues	$	6,912,403		$	7,286,345		$	6,498,003
Wholesale revenues, non-affiliates		394,538			568,797			537,913
Wholesale revenues, affiliates		111,964			286,219			277,832
Other revenues		272,835			270,191			257,904
Total operating revenues		7,691,740			8,411,552			7,571,652
Operating Expenses:
Fuel		2,716,928			2,812,417			2,640,526
Purchased power, non-affiliates		269,136			442,951			332,064
Purchased power, affiliates		709,730			962,100			718,327
Other operations and maintenance		1,494,192			1,580,922			1,561,736
Depreciation and amortization		655,150			636,970			511,180
Taxes other than income taxes		316,532			316,219			291,136
Total operating expenses		6,161,668			6,751,579			6,054,969
Operating Income		1,530,072			1,659,973			1,516,683
Other Income and (Expense):
Allowance for equity funds used during construction		96,788			95,294			68,177
Interest income		2,242			7,219			3,560
Interest expense, net of amounts capitalized		(385,889	)		(345,415	)		(343,461	)
Other income (expense), net		(1,774	)		(9,259	)		14,705
Total other income and (expense)		(288,633	)		(252,161	)		(257,019	)
Earnings Before Income Taxes		1,241,439			1,407,812			1,259,664
Income taxes		410,013			487,504			417,521
Net Income		831,426			920,308			842,143
Dividends on Preferred and Preference Stock		17,381			17,381			6,007
Net Income After Dividends on Preferred and Preference Stock	$	814,045		$	902,927		$	836,136

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

II-196

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009, 2008, and 2007
Georgia Power Company 2009 Annual Report

	2009			2008			2007
				(in thousands)
Operating Activities:
Net income	$	831,426		$	920,308		$	842,143
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		790,581			758,284			616,796
Deferred income taxes		191,382			170,958			(78,010	)
Deferred revenues		(48,962	)		122,965			4,871
Deferred expenses		(4,281	)		1,605			2,950
Allowance for equity funds used during construction		(96,788	)		(95,294	)		(68,177	)
Pension, postretirement, and other employee benefits		(20,032	)		(3,243	)		8,836
Stock based compensation expense		4,592			4,200			5,977
Hedge settlements		(19,016	)		(22,949	)		12,121
Insurance cash surrender value		19,742			—			—
Other, net		20,212			(696	)		15,600
Changes in certain current assets and liabilities —
-Receivables		126,758			(82,996	)		134,276
-Fossil fuel stock		(241,509	)		(91,536	)		(1,211	)
-Materials and supplies		(6,139	)		(20,021	)		(32,998	)
-Prepaid income taxes		21,067			(14,885	)		10,002
-Other current assets		(1,217	)		(18,460	)		(4,359	)
-Accounts payable		(54,328	)		(56,126	)		22,626
-Accrued taxes		(19,445	)		117,524			(33,320	)
-Accrued compensation		(100,547	)		21,525			(30,039	)
-Other current liabilities		24,678			16,788			20,702
Net cash provided from operating activities		1,418,174			1,727,951			1,448,786
Investing Activities:
Property additions		(2,514,972	)		(1,847,953	)		(1,765,345	)
Investment in restricted cash from pollution control bonds		—			—			(59,525	)
Distribution of restricted cash from pollution control revenue bonds		26,849			32,675			—
Nuclear decommissioning trust fund purchases		(989,219	)		(419,086	)		(448,287	)
Nuclear decommissioning trust fund sales		984,340			412,206			441,407
Cost of removal, net of salvage		(56,494	)		(62,722	)		(47,565	)
Change in construction payables, net of joint owner portion		106,008			2,639			24,893
Other investing activities		25,479			(38,198	)		(25,478	)
Net cash used for investing activities		(2,418,009	)		(1,920,439	)		(1,879,900	)
Financing Activities:
Decrease in notes payable, net		(33,137	)		(358,497	)		(17,690	)
Proceeds —
Capital contributions from parent company		931,382			272,894			322,448
Preferred and preference stock		—			—			225,000
Pollution control revenue bonds issuances		416,510			386,485			190,800
Senior notes issuances		1,000,000			1,000,000			1,500,000
Other long-term debt issuances		1,100			301,100			—
Redemptions —
Pollution control revenue bonds		(327,310	)		(335,605	)		—
Capital leases		(1,693	)		(1,125	)		(2,185	)
Senior notes		(333,000	)		(198,097	)		(300,000	)
Other long-term debt		—			—			(762,887	)
Payment of preferred and preference stock dividends		(17,568	)		(17,016	)		(3,143	)
Payment of common stock dividends		(738,900	)		(721,200	)		(689,900	)
Other financing activities		(15,979	)		(19,104	)		(32,787	)
Net cash provided from financing activities		881,405			309,835			429,656
Net Change in Cash and Cash Equivalents		(118,430	)		117,347			(1,458	)
Cash and Cash Equivalents at Beginning of Year		132,739			15,392			16,850
Cash and Cash Equivalents at End of Year	$	14,309		$	132,739		$	15,392
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $39,849, $39,807 and $28,668 capitalized, respectively)	$	341,003		$	309,264		$	317,938
Income taxes (net of refunds)		227,778			279,904			456,852

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

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BALANCE SHEETS

At December 31, 2009 and 2008
Georgia Power Company 2009 Annual Report

Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	14,309		$	132,739
Restricted cash and cash equivalents		—			22,381
Receivables —
Customer accounts receivable		486,885			554,219
Unbilled revenues		172,035			147,978
Under recovered regulatory clause revenues		291,837			338,780
Joint owner accounts receivable		146,932			38,710
Other accounts and notes receivable		62,758			59,189
Affiliated companies		11,775			13,091
Accumulated provision for uncollectible accounts		(9,856	)		(10,732	)
Fossil fuel stock, at average cost		726,266			484,757
Materials and supplies, at average cost		362,803			356,537
Vacation pay		74,566			71,217
Prepaid income taxes		132,668			65,987
Other regulatory assets, current		76,634			118,961
Other current assets		62,651			63,464
Total current assets		2,612,263			2,457,278
Property, Plant, and Equipment:
In service		25,120,034			23,975,262
Less accumulated provision for depreciation		9,493,068			9,101,474
Plant in service, net of depreciation		15,626,966			14,873,788
Nuclear fuel, at amortized cost		339,810			278,412
Construction work in progress		2,521,091			1,434,989
Total property, plant, and equipment		18,487,867			16,587,189
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		66,106			57,163
Nuclear decommissioning trusts, at fair value		580,322			460,430
Miscellaneous property and investments		38,516			40,945
Total other property and investments		684,944			558,538
Deferred Charges and Other Assets:
Deferred charges related to income taxes		608,851			572,528
Deferred under recovered regulatory clause revenues		373,245			425,609
Other regulatory assets, deferred		1,321,904			1,449,352
Other deferred charges and assets		205,492			265,174
Total deferred charges and other assets		2,509,492			2,712,663
Total Assets	$	24,294,566		$	22,315,668

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

II-198

BALANCE SHEETS

At December 31, 2009 and 2008
Georgia Power Company 2009 Annual Report

Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	253,882	$	280,443
Notes payable		323,958		357,095
Accounts payable —
Affiliated		238,599		260,545
Other		602,003		422,485
Customer deposits		200,103		186,919
Accrued taxes —
Accrued income taxes		548		70,916
Unrecognized tax benefits		164,863		128,712
Other accrued taxes		290,174		278,172
Accrued interest		89,228		79,432
Accrued vacation pay		57,662		57,643
Accrued compensation		42,756		135,191
Liabilities from risk management activities		49,788		113,432
Other cost of removal obligations, current		216,000		—
Other regulatory liabilities, current		99,807		60,330
Other current liabilities		84,319		75,846
Total current liabilities		2,713,690		2,507,161
Long-Term Debt(See accompanying statements)		7,782,340		7,006,275
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,389,907		3,064,580
Deferred credits related to income taxes		133,683		140,933
Accumulated deferred investment tax credits		242,496		256,218
Employee benefit obligations		923,177		882,965
Asset retirement obligations		676,705		688,019
Other cost of removal obligations		124,662		396,947
Other regulatory liabilities, deferred		1,234		115,865
Other deferred credits and liabilities		137,790		111,505
Total deferred credits and other liabilities		5,629,654		5,657,032
Total Liabilities		16,125,684		15,170,468
Preferred Stock(See accompanying statements)		44,991		44,991
Preference Stock(See accompanying statements)		220,966		220,966
Common Stockholder’s Equity(See accompanying statements)		7,902,925		6,879,243
Total Liabilities and Stockholder’s Equity	$	24,294,566	$	22,315,668
Commitments and Contingent Matters(See notes)

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

II-199

STATEMENTS OF CAPITALIZATION

At December 31, 2009 and 2008
Georgia Power Company 2009 Annual Report

	2009			2008			2009			2008
	(in thousands)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
5.88% due 2044	$	206,186		$	206,186
Long-term notes payable —
4.10% due 2009		—			125,300
Variable rate (2.3288% at 1/1/09) due 2009		—			150,000
Variable rate (0.80% at 1/1/10) due 2010		250,000			250,000
Variable rate (2.95% at 1/1/10) due 2011		300,000			300,000
4.00% to 5.57% due 2011		102,500			101,100
5.125% due 2012		200,000			200,000
4.90% to 6.00% due 2013		525,000			525,000
4.25% to 8.20% due 2015-2048		4,363,903			3,421,903
Total long-term notes payable		5,741,403			5,073,303
Other long-term debt —
Pollution control revenue bonds:
1.95% to 5.75% due 2016-2048		1,134,080			1,309,190
Variable rate (0.25% at 1/1/10) due 2011		8,330			8,330
Variable rate (0.18% to 0.30% at 1/1/10) due 2016-2049		892,315			628,005
Total other long-term debt		2,034,725			1,945,525
Capitalized lease obligations		62,805			67,948
Unamortized debt discount		(8,897	)		(6,244	)
Total long-term debt (annual interest requirement — $377.6 million)		8,036,222			7,286,718
Less amount due within one year		253,882			280,443
Long-term debt excluding amount due within one year		7,782,340			7,006,275			48.8	%		49.5	%
Preferred and Preference Stock:
Non-cumulative preferred stock
$25 par value — 6.125%
Authorized - 50,000,000 shares
Outstanding - 1,800,000 shares		44,991			44,991
Non-cumulative preference stock
$100 par value — 6.50%
Authorized - 15,000,000 shares
Outstanding - 2,250,000 shares		220,966			220,966
Total preferred and preference stock (annual dividend requirement — $17.4 million)		265,957			265,957			1.7			1.9
Common Stockholder’s Equity:
Common stock, without par value —
Authorized: 20,000,000 shares
Outstanding: 9,261,500 shares		398,473			398,473
Paid-in capital		4,592,350			3,655,731
Retained earnings		2,932,934			2,857,789
Accumulated other comprehensive income (loss)		(20,832	)		(32,750	)
Total common stockholder’s equity		7,902,925			6,879,243			49.5			48.6
Total Capitalization	$	15,951,222		$	14,151,475			100.0	%		100.0	%

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

II-200

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

For the Years Ended December 31, 2009, 2008, and 2007
Georgia Power Company 2009 Annual Report

	Number of
	Common									Accumulated
	Shares		Common		Paid-In		Retained			Other Comprehensive
	Issued		Stock		Capital		Earnings			Income (Loss)			Total
					(in thousands)
Balance at December 31, 2006		9,262	$	398,473	$	3,039,845	$	2,529,826		$	(11,893	)	$	5,956,251
Net income after dividends on preferred and preference stock		—		—		—		836,136			—			836,136
Capital contributions from parent company		—		—		334,931		—			—			334,931
Other comprehensive loss		—		—		—		—			(2,000	)		(2,000	)
Cash dividends on common stock		—		—		—		(689,900	)		—			(689,900	)
Other		—		—		1		1			—			2
Balance at December 31, 2007		9,262		398,473		3,374,777		2,676,063			(13,893	)		6,435,420
Net income after dividends on preferred and preference stock		—		—		—		902,927			—			902,927
Capital contributions from parent company		—		—		280,954		—			—			280,954
Other comprehensive loss		—		—		—		—			(18,857	)		(18,857	)
Cash dividends on common stock		—		—		—		(721,200	)		—			(721,200	)
Other		—		—		—		(1	)		—			(1	)
Balance at December 31, 2008		9,262		398,473		3,655,731		2,857,789			(32,750	)		6,879,243
Net income after dividends on preferred and preference stock		—		—		—		814,045			—			814,045
Capital contributions from parent company		—		—		936,619		—			—			936,619
Other comprehensive income		—		—		—		—			11,918			11,918
Cash dividends on common stock		—		—		—		(738,900	)		—			(738,900	)
Balance at December 31, 2009		9,262	$	398,473	$	4,592,350	$	2,932,934		$	(20,832	)	$	7,902,925

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

II-201

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2009, 2008, and 2007
Georgia Power Company 2009 Annual Report

	2009			2008			2007
				(in thousands)
Net income after dividends on preferred and preference stock	$	814,045		$	902,927		$	836,136
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,133), $(13,150), and $(1,831), respectively		(1,826	)		(20,846	)		(2,938	)
Reclassification adjustment for amounts included in net income, net of tax of $8,651, $1,255, and $278, respectively		13,744			1,989			441
Marketable securities:
Change in fair value, net of tax of $-, $-, and $291, respectively		—			—			497
Total other comprehensive income (loss)		11,918			(18,857	)		(2,000	)
Comprehensive Income	$	825,963		$	884,070		$	834,136

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

II-202

NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2009 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Georgia Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies — Alabama Power Company (Alabama Power), the Company, Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) — 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, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in 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 Plants Hatch and Vogtle.

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 the current year presentation.

The Company is subject to regulation by the Federal Energy Regulatory Commission (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, digital wireless communications, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $506 million in 2009, $490 million in 2008, and $449 million in 2007. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

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, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $398 million in 2009, $410 million in 2008, and $380 million in 2007.

II-203

NOTES (continued)
Georgia Power Company 2009 Annual Report

The Company had an agreement with Southern Power under which the Company operated and maintained Southern Power’s Plants Dahlberg, Franklin, and Wansley at cost. In August 2007, that agreement was terminated and replaced with a service agreement under which the Company provides to Southern Power specifically requested services. Billings under these agreements with Southern Power amounted to $0.5 million in 2009, $1.9 million in 2008, and $6.8 million in 2007.

Southern Company’s 30% ownership interest in Alabama Fuel Products, LLC (AFP), which produced synthetic fuel, was terminated in July 2006. The Company had an agreement with an indirect subsidiary of Southern Company that provided services for AFP. Under this agreement, the Company provided certain accounting functions, including processing and paying fuel transportation invoices, and the Company was reimbursed for its expenses. Amounts billed under this agreement totaled approximately $85 million in 2007. In addition, the Company purchased synthetic fuel from AFP for use at Plant Branch. Synthetic fuel purchases totaled $278 million in 2007. The related party transactions and synthetic fuel purchases were terminated as of December 31, 2007.

The Company has entered into several power purchase agreements (PPA) with Southern Power for capacity and energy. Expenses associated with these PPAs were $411 million, $480 million, and $440 million in 2009, 2008, and 2007, respectively. Additionally, the Company had $24 million and $25 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2009 and 2008, 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 non-fuel expenses, which were $3.9 million in 2009, $8.1 million in 2008, and $5.1 million in 2007. See Note 4 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. The Company neither provided nor received any significant services to or from affiliates in 2009, 2008, or 2007.

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

The traditional 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 the Financial Accounting Standards Board in accounting for the effects of governmental regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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NOTES (continued)
Georgia Power Company 2009 Annual Report

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

	2009			2008			Note
	(in millions)
Deferred income tax charges	$	609	��	$	573			(a	)
Loss on reacquired debt		157			165			(b	)
Vacation pay		75			71			(c, h	)
Underfunded retiree benefit plans		952			921			(e, h	)
Fuel-hedging (realized and unrealized) losses		82			130			(f	)
Building leases		47			49			(i	)
Generating plant outage costs		39			45			(j	)
Other regulatory assets		49			98			(d	)
Asset retirement obligations		116			209			(a, h	)
Other cost of removal obligations		(341	)		(397	)		(a	)
Deferred income tax credits		(134	)		(141	)		(a	)
Environmental compliance cost recovery		(96	)		(135	)		(g	)
Other regulatory liabilities		(1	)		(15	)		(b, d, f	)
Total assets (liabilities), net	$	1,554		$	1,573

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and 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 other cost of removal liabilities will be settled and trued up following completion of the related activities. Other cost of removal obligations include $216 million that may be amortized during 2010. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information.
(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 Georgia PSC over periods not exceeding three years.
(e)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed 42 months. Upon final settlement, costs are recovered through the Company’s fuel cost recovery mechanism.
(g)	This balance represents deferred revenue associated with the environmental compliance cost recovery (ECCR) tariff established in the 2007 Retail Rate Plan (as defined below). The recovery of the forecasted environmental compliance costs was levelized to collect equal annual amounts between January 1, 2008 and December 31, 2010 under the tariff.
(h)	Not earning a return as offset in rate base by a corresponding asset or liability.
(i)	See Note 6 under “Capital Leases.” Recovered over the remaining lives of the buildings through 2026.
(j)	See “Property, Plant, and Equipment.” Recovered over the respective operating cycles, which range from 18 months to 10 years.

In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair value. All regulatory assets and liabilities are reflected in rates.

II-205

NOTES (continued)
Georgia Power Company 2009 Annual Report

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 and 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.

Retail fuel cost recovery rates require periodic filings with the Georgia PSC. See Note 3 under “Retail Regulatory Matters — Fuel Cost Recovery” for information on the Company’s current fuel case proceeding.

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emissions 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. See Note 3 under “Nuclear Fuel Disposal Costs” for additional information.

Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

Property, Plant, and Equipment

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

The Company’s property, plant, and equipment consisted of the following at December 31:

	2009		2008
	(in millions)
Generation	$	12,185	$	11,478
Transmission		3,891		3,764
Distribution		7,603		7,409
General		1,413		1,296
Plant acquisition adjustment		28		28
Total plant in service	$	25,120	$	23,975

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 outage costs over the unit’s operating cycle. The refueling cycles are 18 and 24 months for Plants Vogtle and Hatch, respectively. Also, in accordance with the Georgia PSC, 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.

II-206

NOTES (continued)
Georgia Power Company 2009 Annual Report

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0% in 2009, 2.9% in 2008, and 2.6% in 2007. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC. Effective January 1, 2008, the Company’s depreciation rates were revised by the Georgia PSC.

When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. 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 the Company’s retail rate plan for the three years ended December 31, 2007 (2004 Retail Rate Plan), the Company was ordered to recognize Georgia PSC—certified capacity costs in rates evenly over the three years covered by the 2004 Retail Rate Plan. The Company recorded credits to amortization of $19 million in 2007. The retail rate plan for the three years ending December 31, 2010 (2007 Retail Rate Plan) did not include a similar order.

On August 27, 2009, the Georgia PSC approved an accounting order allowing the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. 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 are reflected in the balance sheets as a regulatory liability. See Note 3 under “Retail Regulatory Matters — Rate Plans” for additional information related to the Company’s cost of removal regulatory liability.

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, 2009 was $580 million. In addition, the Company has retirement obligations related to various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has 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 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 the allowed removal costs in accordance with its regulatory treatment. Any difference between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations 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:

	2009			2008
	(in millions)
Balance beginning of year	$	690		$	664
Liabilities incurred		2			4
Liabilities settled		(7	)		(1	)
Accretion		44			41
Cash flow revisions		(48	)		(18	)
Balance end of year	$	681		$	690

II-207

NOTES (continued)
Georgia Power Company 2009 Annual Report

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 (the 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 Georgia PSC, as well as the Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds’ managers to exercise the standard of care in investing that a “prudent investor” would use in the same circumstances. The FERC regulations also require, except for investments tied to market indices or other mutual funds, that the Funds’ managers may not invest in any securities of the utility for which it manages funds or its affiliates. In addition, the NRC prohibits investments in securities of power reactor licensees. While the Company is allowed to prescribe an overall investment policy to the Funds’ managers, the Company is not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the Company’s management. The Funds’ managers are authorized, within broad limits, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10. Gains and losses, whether realized, unrealized, or identified as other-than-temporary, are recorded in the regulatory liability for asset retirement obligations in the balance sheets and are not included in net income or other comprehensive income. Fair value adjustments, realized gains, and other-than-temporary impairment losses are determined on a specific identification basis.

At December 31, 2009, investment securities in the Funds totaled $580.0 million consisting of equity securities of $428.6 million, debt securities of $138.0 million, and $13.4 million of other securities. At December 31, 2008, investment securities in the Funds totaled $459.1 million, consisting of equity securities of $261.4 million, debt securities of $187.3 million, and $10.4 million of other securities. These amounts exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases.

Sales of the securities held in the Funds resulted in cash proceeds of $984.3 million, $412.2 million, and $441.4 million in 2009, 2008, and 2007, respectively, all of which were re-invested. For 2009, fair value increases, including reinvested interest and dividends and excluding expenses, were $118.7 million, of which $117.8 million relates to securities held in the Funds at December 31, 2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding expenses, were $(143.9) million. Realized gains and other-than-temporary impairment losses were $43.7 million and $(39.1) million, respectively, in 2007. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statement of cash flows as investing cash flows, consistent with the nature of and purpose for which the securities were acquired.

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.

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Georgia Power Company 2009 Annual Report

Site study cost is the estimate to decommission a specific facility as of the site study year. The estimated costs of decommissioning are based on the most current study performed in 2009. The site study costs and accumulated provisions for decommissioning as of December 31, 2009 based on the Company’s ownership interests were as follows:

	Plant Hatch		Plant Vogtle
Decommissioning periods:
Beginning year		2034		2047
Completion year		2063		2067
	(in millions)
Site study costs:
Radiated structures	$	583	$	500
Non-radiated structures		46		71
Total site study costs	$	629	$	571
Accumulated provision	$	360	$	206

The decommissioning periods and site study costs for Plant Vogtle reflect the extended operating license approved by the NRC on June 3, 2009. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these 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, the Company’s decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities. The annual decommissioning costs for ratemaking were $7 million for Plant Vogtle for 2007. Under the 2007 Retail Rate Plan, effective for the years 2008 through 2010, the annual decommissioning cost for ratemaking is $3 million for Plant Vogtle. Based on estimates approved in the 2007 Retail Rate Plan, the Company projected the external trust funds for Plant Hatch would be adequate to meet the decommissioning obligations with no further contributions. The NRC estimates are $531 million and $366 million for Plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.9% and an estimated trust earnings rate of 4.9%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs.

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

In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2009, 2008, and 2007, the average AFUDC rates were 8.0%, 8.2%, and 8.4%, respectively, and AFUDC capitalized was $136.6 million, $135.1 million, and $96.8 million, respectively. AFUDC, net of taxes, was 14.9%, 13.3%, and 10.3% of net income after dividends on preferred and preference stock for 2009, 2008, and 2007, respectively.

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 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.

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Georgia Power Company 2009 Annual Report

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. In 2007, the Company accrued $6.6 million annually that was recoverable through base rates. Effective January 1, 2008, the Company is accruing $21.4 million annually under the 2007 Retail Rate Plan. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.

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, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information. 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 through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2009.

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.

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 reclassifications for amounts included in net income.

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Georgia Power Company 2009 Annual Report

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 considered 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 in the balance sheets. See Note 6 under “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). No contributions to the defined benefit plan are expected for the year ending December 31, 2010. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the FERC. For the year ending December 31, 2010, postretirement trust contributions are expected to total approximately $31 million.

The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to accounting standards related to defined postretirement benefit plans, the Company was required to change the measurement date for its defined postretirement benefit plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the Company adopted the measurement date provisions effective January 1, 2008 resulting in an increase in long-term liabilities of $10 million and an increase in prepaid pension costs of approximately $10 million.

Pension Plans

The total accumulated benefit obligation for the pension plans was $2.4 billion in 2009 and $2.1 billion in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	2,238		$	2,178
Service cost		48			62
Interest cost		147			167
Benefits paid		(122	)		(133	)
Actuarial loss (gain)		206			(36	)
Balance at end of year		2,517			2,238
Change in plan assets
Fair value of plan assets at beginning of year		2,038			3,073
Actual return (loss) on plan assets		314			(910	)
Employer contributions		7			8
Benefits paid		(122	)		(133	)
Fair value of plan assets at end of year		2,237			2,038
Accrued liability	$	(280	)	$	(200	)

At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension plans were $2.4 billion and $135 million, respectively. All pension plan assets are related to the qualified pension plan.

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Georgia Power Company 2009 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). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

The actual composition of the Company’s pension plan assets as of December 31, 2009 and 2008, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		29	%		33	%		34	%
International equity		28			29			23
Fixed income		15			15			14
Special situations		3			—			—
Real estate investments		15			13			19
Private equity		10			10			10
Total		100	%		100	%		100	%

The investment strategy for plan assets related to the Company’s defined benefit plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

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Georgia Power Company 2009 Annual Report

The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	444	$	184	$	—	$	628
International equity*		574		57		—		631
Fixed income:
U.S. Treasury, government, and agency bonds		—		165		—		165
Mortgage- and asset-backed securities		—		45		—		45
Corporate bonds		—		111		—		111
Pooled funds		—		4		—		4
Cash equivalents and other		1		136		—		137
Special situations		—		—		—		—
Real estate investments		69		—		217		286
Private equity		—		—		221		221
Total	$	1,088	$	702	$	438	$	2,228
Liabilities:
Derivatives		(2)		—		—		(2)
Total	$	1,086	$	702	$	438	$	2,226

*   Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
				(in millions)
Assets:
Domestic equity*	$	419		$	171	$	—	$	590
International equity*		377			35		—		412
Fixed income:
U.S. Treasury, government, and agency bonds		—			176		—		176
Mortgage- and asset-backed securities		—			84		—		84
Corporate bonds		—			114		—		114
Pooled funds		—			1		—		1
Cash equivalents and other		9			81		—		90
Special situations		—			—		—		—
Real estate investments		58			—		336		394
Private equity		—			—		196		196
Total	$	863		$	662	$	532	$	2,057
Liabilities:
Derivatives		(3	)		—		—		(3	)
Total	$	860		$	662	$	532	$	2,054

*   Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Georgia Power Company 2009 Annual Report

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
				(in millions)
Beginning balance	$	336		$	196	$	418		$	208
Actual return on investments:
Related to investments held at year end		(98	)		14		(68	)		(56	)
Related to investments sold during the year		(26	)		4		2			10
Total return on investments		(124	)		18		(66	)		(46	)
Purchases, sales, and settlements		5			7		(16	)		34
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	217		$	221	$	336		$	196

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued utilizing matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s pension plans consist of the following:

	2009			2008
	(in millions)
Other regulatory assets, deferred	$	734		$	642
Current liabilities, other		(8	)		(7	)
Employee benefit obligations		(272	)		(193	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2010.

	Prior Service Cost		Net(Gain)Loss
	(in millions)
Balance at December 31, 2009:	$	73	$	661
Balance at December 31, 2008:	$	87	$	555
Estimated amortization in net periodic pension cost in 2010:	$	13	$	2

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Georgia Power Company 2009 Annual Report

The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory Assets			Regulatory Liabilities
	(in millions)
Balance at December 31, 2007	$	64		$	(540	)
Net loss		585			554
Reclassification adjustments:
Amortization of prior service costs		(4	)		(14	)
Amortization of net gain		(3	)		—
Total reclassification adjustments		(7	)		(14	)
Total change		578			540
Balance at December 31, 2008	$	642		$	—
Net loss		108			—
Reclassification adjustments:
Amortization of prior service costs		(14	)		—
Amortization of net gain		(2	)		—
Total reclassification adjustments		(16	)		—
Total change		92			—
Balance at December 31, 2009	$	734		$	—

Components of net periodic pension cost (income) were as follows:

	2009			2008			2007
	(in millions)
Service cost	$	48		$	49		$	51
Interest cost		147			134			126
Expected return on plan assets		(216	)		(211	)		(195	)
Recognized net loss		2			3			3
Net amortization		14			14			14
Net periodic pension cost (income)	$	(5	)	$	(11	)	$	(1	)

Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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, 2009, estimated benefit payments were as follows:

	Benefit Payments
	(in millions)
2010	$	135
2011		140
2012		144
2013		151
2014		162
2015 to 2019		929

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Georgia Power Company 2009 Annual Report

Other Postretirement Benefits

Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

	2009			2008
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	772		$	798
Service cost		10			13
Interest cost		50			61
Benefits paid		(43	)		(47	)
Actuarial loss (gain)		8			(57	)
Plan amendments		(18	)		—
Retiree drug subsidy		3			4
Balance at end of year		782			772
Change in plan assets
Fair value of plan assets at beginning of year		312			427
Actual return (loss) on plan assets		66			(131	)
Employer contributions		31			59
Benefits paid		(40	)		(43	)
Fair value of plan assets at end of year		369			312
Accrued liability	$	(413	)	$	(460	)

Other postretirement benefit 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. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		41	%		34	%		38	%
International equity		22			29			21
Fixed income		31			32			35
Special situations		1			—			—
Real estate investments		3			3			4
Private equity		2			2			2
Total		100	%		100	%		100	%

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio comprises both domestic and international bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Trust-owned life insurance.Some of the Company’s taxable trusts invest in these investments in order to minimize the impact of taxes on the portfolio.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

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Georgia Power Company 2009 Annual Report

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	82	$	29	$	—	$	111
International equity*		20		31		—		51
Fixed income:
U.S. Treasury, government, and agency bonds		—		5		—		5
Mortgage- and asset-backed securities		—		2		—		2
Corporate bonds		—		4		—		4
Pooled funds		—		17		—		17
Cash equivalents and other		—		26		—		26
Trust-owned life insurance		—		126		—		126
Special situations		—		—		—		—
Real estate investments		2		—		8		10
Private equity		—		—		8		8
Total	$	104	$	240	$	16	$	360

*   Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2008:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	69	$	34	$	—	$	103
International equity*		13		21		—		34
Fixed income:
U.S. Treasury, government, and agency bonds		—		5		—		5
Mortgage- and asset-backed securities		—		3		—		3
Corporate bonds		—		4		—		4
Pooled funds		—		9		—		9
Cash equivalents and other		—		22		—		22
Trust-owned life insurance		—		110		—		110
Special situations		—		—		—		—
Real estate investments		2		—		12		14
Private equity		—		—		7		7
Total	$	84	$	208	$	19	$	311

*   Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in millions)
Beginning balance	$	12		$	7	$	14		$	7
Actual return on investments:
Related to investments held at year end		(3	)		1		(1	)		(1	)
Related to investments sold during the year		(1	)		—		—			—
Total return on investments		(4	)		1		(1	)		(1	)
Purchases, sales, and settlements		—			—		(1	)		1
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	8		$	8	$	12		$	7

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued utilizing matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:

	2009			2008
	(in millions)
Other regulatory assets, deferred	$	202		$	261
Employee benefit obligations		(413	)		(460	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2010.

	Prior Service		Net(Gain)		Transition
	Cost		Loss		Obligation
	(in millions)
Balance at December 31, 2009:	$	11	$	167	$	24
Balance at December 31, 2008:	$	20	$	198	$	43
Estimated amortization as net periodic postretirement benefit cost in 2010:	$	1	$	3	$	6

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The components of other comprehensive income, along with the changes in the balance of regulatory assets, related to the other postretirement benefit plans for the plan year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory Assets
	(in millions)
Balance at December 31, 2007	$	171
Net loss		110
Reclassification adjustments:
Amortization of transition obligation		(11	)
Amortization of prior service costs		(3	)
Amortization of net gain		(6	)
Total reclassification adjustments		(20	)
Total change		90
Balance at December 31, 2008	$	261
Net gain		(28	)
Change in prior service costs/transition obligation		(18	)
Reclassification adjustments:
Amortization of transition obligation		(8	)
Amortization of prior service costs		(2	)
Amortization of net gain		(3	)
Total reclassification adjustments		(13	)
Total change		(59	)
Balance at December 31, 2009	$	202

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

	2009			2008			2007
	(in millions)
Service cost	$	10		$	10		$	10
Interest cost		50			50			47
Expected return on plan assets		(30	)		(30	)		(26	)
Net amortization		13			16			19
Net postretirement cost	$	43		$	46		$	50

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2009, 2008, and 2007 by approximately $14 million, $14 million, and $14 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 APBO for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

	Benefit Payments		Subsidy Receipts			Total
	(in millions)
2010	$	50	$	(4	)	$	46
2011		53		(4	)		49
2012		56		(4	)		52
2013		58		(5	)		53
2014		60		(6	)		54
2015 to 2019		317		(38	)		279

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Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual salary increase of 3.50%.

	2009			2008			2007
Discount rate:
Pension plans		5.93	%		6.75	%		6.30	%
Other postretirement benefit plans		5.83			6.75			6.30
Annual salary increase		4.18			3.75			3.75
Long-term return on plan assets:
Pension plans		8.50			8.50			8.50
Other postretirement benefit plans		7.35			7.38			7.37

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2009 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	58	$	51
Service and interest costs		4		4

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $25 million, $25 million, and $24 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 such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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.

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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 the Company, 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. The action was filed concurrently with the issuance of a notice of violation of the NSR provisions to the Company. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against the Company, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 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 or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the

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Georgia Power Company 2009 Annual Report

Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties.

In 2007, the Company’s rates included an annual accrual of $5.4 million for environmental remediation. Beginning in January 2008, the Company is recovering environmental remediation costs through a new base rate tariff (see “Retail Regulatory Matters — Rate Plans” herein) that includes an annual accrual of $1.2 million for environmental remediation. Environmental remediation expenditures are charged against the reserve as they are incurred. The annual accrual amount is expected to be reviewed and adjusted in future regulatory proceedings. As of December 31, 2009, the balance of the environmental remediation liability was $12.5 million.

The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated. The final outcome of these matters cannot now be determined. 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.

By letter dated September 30, 2008, the EPA advised the Company that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices from the EPA. The Company, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including the Company, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact 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, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

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On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that the Company possesses or has exercised any market power. The agreement likewise does not require the Company to make any refunds related to sales during the 15-month refund period. Under the agreement, the Company will donate $0.7 million to nonprofit organizations in the State of Georgia for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

Income Tax Matters

The Company’s 2005 through 2008 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. The Company has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, the Company filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. See Note 5 under “Unrecognized Tax Benefits” for additional information. If the Company prevails, these claims could have a significant, and possibly material, positive effect on the Company’s net income. If the Company is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on the Company’s cash flow. The ultimate outcome of this matter cannot now be determined.

Nuclear Fuel Disposal Costs

The Company has contracts with the United States, acting through the U.S. Department of Energy (DOE), which 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.

In July 2007, the U.S. Court of Federal Claims awarded the Company approximately $30 million, based on its ownership interests, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Hatch and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal. In April 2008, the U.S. Court of Appeals for the Federal Circuit granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. The U.S. Court of Appeals for the Federal Circuit has left the stay of appeals in place pending the decision in an appeal of another case involving spent nuclear fuel contracts.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit denied a similar request by the government to stay this proceeding. The complaint does not contain

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any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of December 31, 2009 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. 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 expected life of the plant.

Retail Regulatory Matters

Rate Plans

In December 2004, the Georgia PSC approved the Company’s retail rate plan for the years 2005 through 2007 (2004 Retail Rate Plan). Under the terms of the 2004 Retail Rate Plan, the Company’s earnings were evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining one-third retained by the Company. Retail rates and customer fees 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 2007, the Company refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to earnings for 2007.

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan for the years 2008 through 2010. Under the 2007 Retail Rate Plan, the Company’s earnings are evaluated against a retail ROE range of 10.25% to 12.25%. Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for cost recovery of transmission, distribution, generation, and other investments, as well as increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery of costs related to environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008.

In connection with the 2007 Retail Rate Plan, the Company agreed that it would not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. The economic recession has significantly reduced the Company’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce expenses, the Company’s projected retail ROE for both 2009 and 2010 was below 10.25%. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, the Company filed a request with the Georgia PSC for an accounting order that would allow the Company to amortize up to $324 million of its regulatory liability related to other cost of removal obligations.

On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, the Company was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail ROE. For the year ended December 31, 2009, the Company amortized $41 million of the regulatory liability. In addition, the Company may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE.

The Company is required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued.

Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. In February 2007, the Georgia PSC approved an increase in the Company’s total annual billings of approximately $383 million effective March 1, 2007. On May 20, 2008, the Georgia PSC approved an additional increase of approximately $222 million effective June 1, 2008. The order in that case required the Company to file a new fuel cost recovery rate by March 1, 2009, which was subsequently approved by the Georgia PSC to be delayed until December 15, 2009. On December 15, 2009, the Company filed for a fuel cost recovery increase with the Georgia PSC. On February 22, 2010, the Company, the Georgia PSC Public Interest Advocacy Staff, and three customer groups entered into a stipulation to resolve the case, subject to approval by the Georgia PSC (the Stipulation). Under the terms of the Stipulation, the Company’s annual fuel cost recovery billings will increase by approximately $425 million. In addition, the Company will implement an interim fuel rider, which would allow the Company to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds budget by more than $75 million. The Company is required to file its next fuel case by March 1, 2011. The Georgia PSC is scheduled to vote on the Stipulation on March 11, 2010 with the new fuel rates to become effective April 1, 2010. The ultimate outcome of this matter cannot be determined at this time.

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As of December 31, 2008, the Company had a total under recovered fuel cost balance of approximately $764.4 million. As of December 31, 2009, the Company’s under recovered fuel balance totaled approximately $665 million, which if the Stipulation is approved, the Company will recover over 32 months beginning April 1, 2010. Therefore, approximately $373 million of the under recovered regulatory clause revenues for the Company is included in deferred charges and other assets at December 31, 2009.

Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow.

Construction

Nuclear

On August 26, 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern Nuclear, on behalf of the Company, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). See Note 4 for additional information on these co-owners. In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively.

In April 2008, the Company, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain price escalations and adjustments, including certain index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. The Company’s proportionate share is 45.7%.

On February 23, 2010, the Company, acting for itself and as agent for the Owners, and the Consortium entered into an amendment to the Vogtle 3 and 4 Agreement. The amendment, which is subject to the approval of the Georgia PSC, replaces certain of the index-based adjustments to the purchase price with fixed escalation amounts.

The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement.

The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve the inclusion of the related construction work in progress accounts in rate base.

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On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow the Company to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective on January 1, 2011. With respect to Plant Vogtle Units 3 and 4, this legislation allows the Company to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion.

On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. The Company believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions.

On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. The Company is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds.

On August 31, 2009, the Company filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any proposed change to the estimated construction cost as certified by the Georgia PSC in March 2009. On February 25, 2010, the Georgia PSC approved the expenditures made by the Company pursuant to the certification through June 30, 2009. The Georgia PSC also ordered that in its future semi-annual construction monitoring reports, the Company will report against a total certified cost of approximately $6.1 billion, which is the effective certified amount after giving effect to the Georgia Nuclear Energy Financing Act as described above. The Company will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

The ultimate outcome of these matters cannot be determined at this time.

Other Construction

On August 10, 2009, the Company filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. On September 30, 2009, the Company amended the report. As amended, the report includes a request for an increase in the certified costs to construct Plant McDonough. The Georgia PSC held a hearing in December 2009 and is scheduled to render its decision on March 16, 2010. The ultimate outcome of this matter cannot be determined at this time.

4. JOINT OWNERSHIP AGREEMENTS

The Company and 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 these units is sold equally to the Company and Alabama Power under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, debt service, and return on investment, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party’s right to cancel upon two year’s notice. The Company accounts for SEGCO using the equity method.

The Company’s share of expenses included in purchased power from affiliates in the statements of income is as follows:

	2009		2008		2007
	(in millions)
Energy	$	44	$	86	$	66
Capacity		43		41		42
Total	$	87	$	127	$	108

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The Company owns undivided interests in Plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with OPC, MEAG Power, Dalton, 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 and Florida Power Corporation (Progress Energy Florida) jointly own a combustion turbine unit (Intercession City) operated by Progress Energy Florida.

At December 31, 2009, 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)
Units 1 and 2		45.7	%	$	3,285	$	1,916
Plant Hatch (nuclear)		50.1			937		522
Plant Wansley (coal)		53.5			696		195
Plant Scherer (coal)
Units 1 and 2		8.4			133		70
Unit 3		75.0			723		339
Rocky Mountain (pumped storage)		25.4			175		106
Intercession City (combustion-turbine)		33.3			12		3

At December 31, 2009, the portion of total construction work in progress related to Plants Wansley, Scherer, and Vogtle Units 3 and 4 was $5 million, $247 million, and $611 million, respectively. Construction at Plants Wansley and Scherer relates primarily to environmental projects. See Note 3 under “Construction — Nuclear” for information on Plant Vogtle Units 3 and 4.

The Company’s proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.

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 and no subsidiary is allocated more expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

Current and Deferred Income Taxes

The transfer of the Plant McIntosh construction project from Southern Power to the Company in 2005 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 related deferred taxes of $3.9 million as it is reflected in Southern Power’s future taxable income. Of this amount, $3.5 million is included in Other Deferred Credits and $0.4 million is included in Affiliated Accounts Payable in the balance sheets at December 31, 2009.

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 is reimbursing the Company for the remaining balance of the related deferred taxes of $6.7 million as it is reflected in the Company’s future taxable income. Of this amount, $5.7 million is included in Other Deferred Debits and $1.0 million is included in Affiliated Accounts Receivable in the balance sheets at December 31, 2009.

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Georgia Power Company 2009 Annual Report

Details of income tax provisions are as follows:

	2009		2008		2007
	(in millions)
Federal —
Current	$	211	$	284	$	442
Deferred		175		155		(72	)
		386		439		370
State —
Current		7		32		54
Deferred		17		16		(6	)
		24		48		48
Total	$	410	$	487	$	418

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:

	2009		2008
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	2,923	$	2,554
Property basis differences		585		594
Employee benefit obligations		184		174
Fuel clause under recovery		270		311
Premium on reacquired debt		64		67
Emissions allowances		22		—
Regulatory assets associated with employee benefit obligations		362		349
Asset retirement obligations		263		267
Other		70		72
Total		4,743		4,388
Deferred tax assets —
Federal effect of state deferred taxes		177		189
Employee benefit obligations		482		457
Other property basis differences		117		127
Other deferred costs		65		99
Cost of removal obligations		109		—
State tax credit carry forward		99		—
Other comprehensive income		12		10
Unbilled fuel revenue		42		42
Asset retirement obligations		263		267
Environmental capital cost recovery		37		52
Other		38		21
Total		1,441		1,264
Total deferred tax liabilities, net		3,302		3,124
Portion included in current assets/(liabilities), net		88		(60	)
Accumulated deferred income taxes	$	3,390	$	3,064

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Georgia Power Company 2009 Annual Report

At December 31, 2009, tax-related regulatory assets were $609 million and tax-related regulatory liabilities were $134 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. In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $13.7 million in 2009 and $13.0 million annually in 2008 and 2007. At December 31, 2009, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		1.2			2.2			2.4
Non-deductible book depreciation		1.1			0.9			1.1
AFUDC equity		(2.7	)		(2.4	)		(1.9	)
Donations		(0.8	)		—			(1.7	)
Other		(0.8	)		(1.1	)		(1.7	)
Effective income tax rate		33.0	%		34.6	%		33.2	%

The decrease in the Company’s 2009 effective tax rate is primarily the result of the Company’s donation of 5,111 acres of land to the State of Georgia combined with an increase in non-taxable AFUDC equity and a decrease in tax deductions related to unrecognized tax benefits. See “Unrecognized Tax Benefits” and Note 3 under “Income Tax Matters” for additional information on these unrecognized tax benefits and related litigation.

The increase in the Company’s 2008 effective tax rate is primarily the result of a decrease in donations for 2008 as a result of the Tallulah Gorge land donation in 2007 combined with an increase in non-taxable AFUDC equity. In 2007, the Company donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia.

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, the Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits increased by $44.3 million, resulting in a balance of $181.4 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009			2008			2007
	(in millions)
Unrecognized tax benefits at beginning of year	$	137		$	89		$	65
Tax positions from current periods		44			47			20
Tax positions from prior periods		1			5			4
Reductions due to settlements		—			(4	)		—
Reductions due to expired statute of limitations		(1	)		—			—
Balance at end of year	$	181		$	137		$	89

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Georgia Power Company 2009 Annual Report

The tax positions from current periods increase for 2009 relate primarily to the Georgia state tax credits litigation, the production activities deduction tax position, and other miscellaneous uncertain tax positions. The tax positions increase from prior periods for 2009 relates primarily to the production activities deduction tax position. See Note 3 under “Income Tax Matters” for additional information.

Impact on the Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
			(in millions)
Tax positions impacting the effective tax rate	$	181	$	134	$	86
Tax positions not impacting the effective tax rate		—		3		3
Balance of unrecognized tax benefits	$	181	$	137	$	89

The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at the Company. See Note 3 under “Income Tax Matters” for additional information.

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008		2007
			(in millions)
Interest accrued at beginning of year	$	14	$	7	$	3
Interest reclassified due to settlements		—		—		—
Interest accrued during the year		6		7		4
Balance at end of year	$	20	$	14	$	7

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

Substantially all of the Company’s unrecognized tax benefits impacting the effective tax rate are associated with the state income tax credits discussed in Note 3 under “Income Tax Matters.” Settlement of this litigation could occur within the next 12 months, which would reduce the balance of the uncertain tax position by these amounts.

6. FINANCING

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 $206 million, which constitute substantially all of the assets of these trusts and are reflected in the balance sheets as Long-term Debt. 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, 2009, preferred securities of $200 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:

	2009		2008
	(in millions)
Capital lease	$	4	$	5
Senior notes		250		275
Total	$	254	$	280

Maturities through 2014 applicable to total long-term debt are as follows: $254 million in 2010; $415 million in 2011; $205 million in 2012; $530 million in 2013; and $5 million in 2014.

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Georgia Power Company 2009 Annual Report

Pollution Control Revenue 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, 2009 and 2008 was $2.0 billion and $1.9 billion, respectively. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

Senior Notes

The Company issued $1.0 billion aggregate principal amount of unsecured senior notes in 2009. The proceeds of the issuance were used to repay a portion of the Company’s short-term indebtedness, fund note redemptions totaling $333 million, redeem pollution control revenue bonds totaling $327.3 million, and fund the Company’s continuous construction program. At December 31, 2009 and 2008, the Company had $5.4 billion and $4.8 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $63 million and $68 million at December 31, 2009 and 2008, respectively.

Bank Term Loans

At December 31, 2009 and 2008, the Company had a $300 million bank loan outstanding, which matures in March 2011.

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, 2009 and 2008, the Company had a capitalized lease obligation for its corporate headquarters building of $62 million and $66 million, respectively, with an interest rate of 8.0%. 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.”

At December 31, 2009 and 2008, the Company had capitalized lease obligations of $0.6 million and $0.8 million, respectively, for its vehicles. 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 all capital leases in 2009, 2008, and 2007 was $8.7 million, $9.7 million, and $9.2 million, respectively.

Outstanding Classes of Capital Stock

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company’s Class A preferred stock ranks senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the Class A preferred stock and preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock. In addition, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Bank Credit Arrangements

At December 31, 2009, the Company had credit arrangements with banks totaling $1.7 billion, of which $12 million was used to support outstanding letters of credit. Of these facilities, $595 million expire during 2010, with the remaining $1.1 billion expiring in

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Georgia Power Company 2009 Annual Report

2012. $40 million of the facilities that expire in 2010 provides 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 average less than 3/8 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.

The credit arrangements contain covenants that limit the ratio of indebtedness to capitalization (each as defined in the arrangements) to 65%. For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities. 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, 2009, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings.

The $1.7 billion of unused credit arrangements provides liquidity support to the Company’s variable rate pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2009 was $901 million. In addition, the Company borrows under a commercial paper program. The amount of commercial paper outstanding at December 31, 2009, 2008, and 2007 was $324 million, $256 million, and $616 million, respectively. The Company also had $100 million of short-term bank loans outstanding at December 31, 2008. Commercial paper and short-term bank loans are included in notes payable on the balance sheets.

During 2009, the peak amount of short-term debt outstanding was $757 million and the average amount outstanding was $348 million. The average annual interest rate on short-term debt in 2009 and 2008 was 0.4% and 2.9%, respectively.

7. COMMITMENTS

Construction Program

The Company currently estimates property additions to be approximately $2.5 billion, $2.4 billion, and $2.8 billion in 2010, 2011, and 2012, respectively. These amounts include $198 million, $109 million, and $115 million in 2010, 2011, and 2012, respectively, for construction expenditures related to contractual purchase commitments for nuclear fuel included under “Fuel Commitments.” The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program. See Note 3 under “Construction” for additional information.

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 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, which are subject to price escalation, are made quarterly based on actual operating hours of the respective units. Total payments to GE under this agreement are currently estimated at $171.5 million over the remaining term of the agreement, which is currently projected to be approximately nine 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 estimated at $8 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.

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Georgia Power Company 2009 Annual Report

The Company has entered into a LTSA with Mitsubishi Power Systems Americas, Inc. (MPS) for the purpose of providing certain parts and maintenance services for the three combined cycle units under construction at Plant McDonough, which are scheduled to go into service in February 2011, June 2011, and June 2012, respectively. The LTSA stipulates that MPS will perform all planned maintenance on each covered unit which includes the cost of all materials and services. MPS is also obligated to cover costs of unplanned maintenance on the gas turbines subject to limits specified in the LTSA. This LTSA will begin in 2011 and is in effect through two major inspection cycles per covered unit. Periodic payments to MPS are to be made quarterly and will also be made based on the scheduled inspections for the respective covered units. Payments to MPS under this agreement, which are subject to price escalation, are currently estimated to be $536.8 million for the term of the agreement which is expected to be between 12 and 13 years. However, the LTSA contains various termination provisions at the option of the Company.

Limestone Commitments

As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 3.3 million tons, equating to approximately $101.0 million through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $19.3 million in 2010, $14.8 million in 2011, $15.2 million in 2012, $15.5 million in 2013, and $16.0 million in 2014.

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 emissions 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, 2009.

Total estimated minimum long-term commitments at December 31, 2009 were as follows:

	Commitments
	Natural Gas		Coal		Nuclear Fuel
			(in millions)
2010	$	473	$	2,239	$	198
2011		575		1,843		109
2012		453		766		115
2013		422		525		111
2014		350		434		60
2015 and thereafter		3,414		1,533		207
Total	$	5,687	$	7,340	$	800

Additional commitments for fuel will be required to supply the Company’s future needs. Total charges for nuclear fuel included in fuel expense were $82 million, $77 million, and $79 million for the years 2009, 2008, and 2007, respectively.

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 traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

Purchased Power Commitments

The Company has commitments regarding a portion of a 5% interest in Plant Vogtle owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power’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

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Georgia Power Company 2009 Annual Report

variable operating costs. Portions of the capacity payments 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. Generally, the cost of such capacity and energy is included in purchased power from non-affiliates in the statements of income. Capacity payments totaled $47 million, $48 million, and $46 million in 2009, 2008, and 2007, respectively. The Company also has entered into other various long-term PPAs. Estimated total long-term obligations under these commitments at December 31, 2009 were as follows:

	Vogtle		Affiliated		Non-Affiliated
	Capacity Payments		PPAs		PPAs
	(in millions)
2010	$	55	$	153	$	135
2011		53		119		142
2012		47		107		115
2013		22		107		108
2014		18		108		109
2015 and thereafter		86		488		1,365
Total	$	281	$	1,082	$	1,974

Certain PPAs reflected in the table are accounted for as operating leases.

Operating Leases

The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $43 million for 2009, $52 million for 2008, and $55 million for 2007.

At December 31, 2009, estimated minimum lease payments for these noncancelable operating leases were as follows:

	Minimum Lease Payments
	Rail Cars		Other		Total
	(in millions)
2010	$	30	$	7	$	37
2011		30		5		35
2012		16		3		19
2013		12		3		15
2014		10		3		13
2015 and thereafter		15		2		17
Total	$	113	$	23	$	136

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 $39.7 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. A majority of the rental expenses related to the rail car leases are fully recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates.

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.

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Georgia Power Company 2009 Annual Report

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, 2009, there were 1,954 current and former employees of the Company participating in the stock option plan, and there were 21 million shares of Southern Company common stock remaining available for awards under this plan. 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. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. 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. For certain stock option awards, a change in control will provide accelerated vesting.

The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:

Year Ended December 31	2009			2008			2007
Expected volatility		15.6	%		13.1	%		14.8	%
Expected term(in years)		5.0			5.0			5.0
Interest rate		1.9	%		2.8	%		4.6	%
Dividend yield		5.4	%		4.5	%		4.3	%
Weighted average grant-date fair value	$	1.80		$	2.37		$	4.12

The Company’s activity in the stock option plan for 2009 is summarized below:

	Shares Subject to			Weighted Average
	Option			Exercise Price
Outstanding at December 31, 2008		7,992,436		$	31.90
Granted		2,489,671			31.38
Exercised		(121,447	)		20.59
Cancelled		(37,736	)		32.71
Outstanding at December 31, 2009		10,322,924		$	31.90
Exercisable at December 31, 2009		6,870,135		$	31.35

The number of stock options vested, and expected to vest in the future, as of December 31, 2009 was not significantly different from the number of stock options outstanding at December 31, 2009 as stated above. At December 31, 2009, the weighted average remaining contractual term for the options outstanding and options exercisable was 5.9 years and 4.6 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $23.1 million and $18.7 million, respectively.

As of December 31, 2009, there was $1.4 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.

For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option awards recognized in income was $4.6 million, $4.2 million, and $6.0 million, respectively, with the related tax benefit also recognized in income of $1.8 million, $1.6 million, and $2.3 million, respectively.

II-235

NOTES (continued)
Georgia Power Company 2009 Annual Report

The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $1.7 million, $10.6 million, and $17.4 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.7 million, $4.1 million, and $6.7 million, respectively, for the years ended December 31, 2009, 2008, and 2007.

9. NUCLEAR INSURANCE

Under the Price-Anderson Amendments 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 the Company’s Plants Hatch and Vogtle. The Act provides funds up to $12.6 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 $375 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 commercial nuclear reactors. The Company could be assessed up to $117.5 million per incident for each licensed reactor it operates but not more than an aggregate of $17.5 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, based on its ownership and buyback interests, is $237 million, per incident, but not more than an aggregate of $35 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013.

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. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses.

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. The Company purchases the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week deductible 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 $50 million.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

II-236

NOTES (continued)
Georgia Power Company 2009 Annual Report

10. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Nuclear decommissioning trusts:(a)
Domestic equity	$	428	$	1	$	—	$	429
U.S. Treasury and government agency securities		—		31		—		31
Municipal bonds		—		23		—		23
Corporate bonds		—		61		—		61
Mortgage and asset backed securities		—		23		—		23
Other		—		13		—		13
Total	$	428	$	152	$	—	$	580
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	75
Interest rate derivatives		—		2		—		2
Total	$	—	$	77	$	—	$	77

(a) Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 11 for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. See Note 1 under “Nuclear Decommissioning” for additional information. All of these financial instruments and investments are valued primarily using the market approach.

II-237

NOTES (continued)
Georgia Power Company 2009 Annual Report

As of December 31, 2009, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

			Unfunded	Redemption	Redemption
As of December 31, 2009:	Fair Value		Commitments	Frequency	Notice Period
	(in millions)
Nuclear decommissioning trusts:
Corporate bonds – commingled funds	$	14	None	Daily	1 to 3 days
Other – commingled funds		13	None	Daily	Not applicable

The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five year final maturity with put features or floating rates with a reset date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity.

The Company’s financial instruments for which the carrying amount did not equal fair value at December 31 were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2009	$	7,973	$	8,059
2008	$	7,219	$	7,096

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

11. DERIVATIVES

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 its exposures, where possible, 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. The Company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

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 manages fuel-hedging programs, implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

II-238

NOTES (continued)
Georgia Power Company 2009 Annual Report

Energy-related derivative contracts are accounted for in one of two methods:

• Regulatory Hedges– Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clauses.

• Not Designated– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, which is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At December 31, 2009, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Net	Longest
Purchased	Hedge	Longest Non-Hedge
mmBtu*	Date	Date
(in millions)
71	2014	—

* mmBtu - million British thermal units

Interest Rate Derivatives

The Company also enters into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in other comprehensive income (OCI) and are reclassified into earnings at the same time the hedged transactions affect earnings.

At December 31, 2009, the Company had outstanding interest rate derivatives designated as cash flow hedges of existing debt as follows:

		Weighted		Fair Value
		Average		Gain (Loss)
Notional	Variable Rate	Fixed Rate	Hedge Maturity	December 31,
Amount	Received	Paid	Date	2009
(in millions)				(in millions)
$300	1-month LIBOR	2.43%	April 2010	$(2)

For the year ended December 31, 2009, the Company realized net losses of $19 million upon termination of certain interest rate derivatives at the same time it issued debt. The effective portion of these losses has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings.

The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2010 are $12.8 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037.

II-239

NOTES (continued)
Georgia Power Company 2009 Annual Report

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

	Asset Derivatives							Liability Derivatives
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in millions)							(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:	Other current assets	$	—		$	5		Liabilities from risk management activities	$	47	$	85
	Other deferred charges and assets		—			—		Other deferred credits and liabilities		28		33
Total derivatives designated as hedging instruments for regulatory purposes		$	—		$	5			$	75	$	118
Derivatives designated as hedging instruments in cash flow hedges
Interest rate derivatives:	Other current assets	$	—		$	—		Liabilities from risk management activities	$	2	$	28
	Other deferred charges and assets		—			—		Other deferred credits and liabilities		—		1
Total derivatives designated as hedging instruments in cash flow hedges		$	—		$	—			$	2	$	29
Total		$	—		$	5			$	77	$	147
All derivative instruments are measured at fair value. See Note 10 for additional information. At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
	Unrealized Losses							Unrealized Gains
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in millions)							(in millions)
Energy-related derivatives:	Other regulatory assets, current	$	(47	)	$	(85	)	Other regulatory liabilities, current	$	—	$	5
	Other regulatory assets, deferred		(28	)		(33	)	Other regulatory liabilities, deferred		—		—
Total energy-related derivative gains (losses)		$	(75	)	$	(118	)		$	—	$	5

II-240

NOTES (continued)
Georgia Power Company 2009 Annual Report

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in									Gain (Loss) Reclassified from Accumulated OCI into Income
Derivatives in Cash Flow	OCI on Derivative									(Effective Portion)
Hedging Relationships	(Effective Portion)										Amount
Derivative Category	2009			2008			2007			Statements of Income Location	2009			2008			2007
	(in millions)										(in millions)
Interest rate derivatives	$	(3	)	$	(34	)	$	(5	)	Interest expense	$	(22	)	$	(3	)	$	(1	)

There was no material ineffectiveness recorded in earnings for any period presented.

For all years presented, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial.

Contingent Features

The Company has certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2009, the fair value of derivative liabilities with contingent features was $17 million.

At December 31, 2009, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33.3 million.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participated in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2009 and 2008 is as follows:

					Net Income After
	Operating		Operating		Dividends on Preferred
Quarter Ended	Revenues		Income		and Preference Stock
	(in millions)
March 2009	$	1,766	$	272	$	122
June 2009		1,874		369		190
September 2009		2,327		683		388
December 2009		1,725		206		114
March 2008	$	1,865	$	325	$	176
June 2008		2,111		442		248
September 2008		2,644		711		402
December 2008		1,792		182		77

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

II-241

SELECTED FINANCIAL AND OPERATING DATA 2005-2009
Georgia Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands)	$	7,691,740	$	8,411,552	$	7,571,652	$	7,245,644	$	7,075,837
Net Income after Dividends on Preferred and Preference Stock (in thousands)	$	814,045	$	902,927	$	836,136	$	787,225	$	744,373
Cash Dividends on Common Stock (in thousands)	$	738,900	$	721,200	$	689,900	$	630,000	$	582,800
Return on Average Common Equity (percent)		11.01		13.56		13.50		13.80		14.08
Total Assets (in thousands)	$	24,294,566	$	22,315,668	$	20,822,761	$	19,308,730	$	17,898,445
Gross Property Additions (in thousands)	$	2,646,158	$	1,953,448	$	1,862,449	$	1,276,889	$	958,563
Capitalization (in thousands):
Common stock equity	$	7,902,925	$	6,879,243	$	6,435,420	$	5,956,251	$	5,452,083
Preferred and preference stock		265,957		265,957		265,957		44,991		43,909
Long-term debt		7,782,340		7,006,275		5,937,792		5,211,912		5,365,323
Total (excluding amounts due within one year)	$	15,951,222	$	14,151,475	$	12,639,169	$	11,213,154	$	10,861,315
Capitalization Ratios (percent):
Common stock equity		49.5		48.6		50.9		53.1		50.2
Preferred and preference stock		1.7		1.9		2.1		0.4		0.4
Long-term debt		48.8		49.5		47.0		46.5		49.4
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
Preferred and 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		2,043,661		2,039,503		2,024,520		1,998,643		1,960,556
Commercial		295,375		295,925		295,478		294,654		289,009
Industrial		8,202		8,248		8,240		8,008		8,290
Other		6,580		5,566		4,807		4,371		4,143
Total		2,353,818		2,349,242		2,333,045		2,305,676		2,261,998
Employees (year-end)		8,599		9,337		9,270		9,278		9,273

N/A = Not Applicable.

II-242

SELECTED FINANCIAL AND OPERATING DATA 2005-2009 (continued)
Georgia Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands):
Residential	$	2,686,155	$	2,648,176	$	2,442,501	$	2,326,190	$	2,227,137
Commercial		2,825,602		2,917,270		2,576,058		2,423,568		2,357,077
Industrial		1,318,070		1,640,407		1,403,852		1,382,213		1,406,295
Other		82,576		80,492		75,592		73,649		73,854
Total retail		6,912,403		7,286,345		6,498,003		6,205,620		6,064,363
Wholesale — non-affiliates		394,538		568,797		537,913		551,731		524,800
Wholesale — affiliates		111,964		286,219		277,832		252,556		275,525
Total revenues from sales of electricity		7,418,905		8,141,361		7,313,748		7,009,907		6,864,688
Other revenues		272,835		270,191		257,904		235,737		211,149
Total	$	7,691,740	$	8,411,552	$	7,571,652	$	7,245,644	$	7,075,837
Kilowatt-Hour Sales (in thousands):
Residential		26,272,226		26,412,131		26,840,275		26,206,170		25,508,472
Commercial		32,592,831		33,058,109		33,056,632		32,112,430		31,334,182
Industrial		21,810,062		24,163,566		25,490,035		25,577,006		25,832,265
Other		671,390		670,588		697,363		660,285		737,343
Total retail		81,346,509		84,304,394		86,084,305		84,555,891		83,412,262
Wholesale — non-affiliates		5,206,949		9,756,260		10,577,969		10,685,456		10,588,891
Wholesale — affiliates		2,504,437		3,694,640		5,191,903		5,463,463		5,033,165
Total		89,057,895		97,755,294		101,854,177		100,704,810		99,034,318
Average Revenue Per Kilowatt-Hour (cents):
Residential		10.22		10.03		9.10		8.88		8.73
Commercial		8.67		8.82		7.79		7.55		7.52
Industrial		6.04		6.79		5.51		5.40		5.44
Total retail		8.50		8.64		7.55		7.34		7.27
Wholesale		6.57		6.36		5.17		4.98		5.12
Total sales		8.33		8.33		7.18		6.96		6.93
Residential Average Annual Kilowatt-Hour Use Per Customer		12,848		12,969		13,315		13,216		13,119
Residential Average Annual Revenue Per Customer	$	1,314	$	1,300	$	1,212	$	1,173	$	1,145
Plant Nameplate Capacity Ratings (year-end) (megawatts)		15,995		15,995		15,995		15,995		15,995
Maximum Peak-Hour Demand (megawatts):
Winter		15,173		14,221		13,817		13,528		14,360
Summer		16,080		17,270		17,974		17,159		16,925
Annual Load Factor (percent)		60.7		58.4		57.5		61.8		59.4
Plant Availability (percent):
Fossil-steam		92.5		91.0		90.8		91.4		90.0
Nuclear		88.4		89.8		92.4		90.7		89.3
Source of Energy Supply (percent):
Coal		52.3		58.7		61.5		59.0		60.7
Nuclear		16.2		14.8		14.6		14.4		14.5
Hydro		1.8		0.6		0.5		0.9		1.9
Oil and gas		7.7		5.1		5.5		5.0		3.0
Purchased power -
From non-affiliates		4.4		5.1		3.8		3.8		4.6
From affiliates		17.6		15.7		14.1		16.9		15.3
Total		100.0		100.0		100.0		100.0		100.0

II-243

GULF POWER COMPANY

FINANCIAL SECTION

II-244

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Gulf Power Company 2009 Annual Report

The management of Gulf Power Company (the “Company”) 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 the 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. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

/s/ Susan N. Story

Susan N. Story
President and Chief Executive Officer

/s/ Philip C. Raymond

Philip C. Raymond
Vice President and Chief Financial Officer

February 25, 2010

II-245

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, 2009 and 2008, 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, 2009. 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 financial statements (pages II-268 to II-306) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

II-246

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Company 2009 Annual Report

OVERVIEW

Business Activities

Gulf Power Company (the Company) operates as a vertically integrated utility providing electricity to retail 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 constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge the Company for the foreseeable future.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective energy to over 425,000 customers, the Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. 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. The 2009 Peak Season EFOR of 2.11% was better than the target. 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 performance for 2009 was better than the target for these reliability measures. The performance for net income after dividends on preference stock in 2009 was below target. Net income after dividends on preference stock is the primary measure of the Company’s financial performance.

The Company’s 2009 results compared with its targets for some of these key indicators are reflected in the following chart:

	2009	2009
	Target	Actual
Key Performance Indicator	Performance	Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season EFOR	3.00% or less	2.11%
Net income after dividends on preference stock	$112.5 million	$111.2 million

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance.

Earnings

The Company’s 2009 net income after dividends on preference stock was $111.2 million, an increase of $12.9 million from the previous year. In 2008, net income after dividends on preference stock was $98.3 million, an increase of $14.2 million from the previous year. In 2007, net income after dividends on preference stock was $84.1 million, an increase of $8.1 million from the previous year. The increase in net income after dividends on preference stock in 2009 was due primarily to increased allowance for funds used during construction (AFUDC) equity, which is non-taxable, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales. The increase in net income after dividends on preference stock in 2008 was due primarily to higher wholesale revenues from non-affiliates, increased AFUDC equity, and a gain on the sale of assets.

II-247

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

The increase in net income after dividends on preference stock in 2007 was due primarily to increases in retail revenues, earnings on additional investments in environmental controls through the environment cost recovery provision, and related AFUDC equity, partially offset by non-fuel operating expenses.

RESULTS OF OPERATIONS

A condensed statement of income follows:

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008			2007
	(in millions)
Operating revenues	$	1,302.2		$	(84.9	)	$	127.4		$	55.9
Fuel		573.4			(62.2	)		62.2			38.5
Purchased power		92.0			(17.4	)		37.9			(2.3	)
Other operations and maintenance		260.3			(17.2	)		7.1			10.9
Depreciation and amortization		93.4			8.6			(0.8	)		(3.6	)
Taxes other than income taxes		94.5			7.3			4.2			3.2
Total operating expenses		1,113.6			(80.9	)		110.6			46.7
Operating income		188.6			(4.0	)		16.8			9.2
Total other income and (expense)		(18.2	)		15.8			6.7			1.3
Income taxes		53.0			(1.1	)		7.0			1.8
Net income		117.4			12.9			16.5			8.7
Dividends on preference stock		6.2			—			2.3			0.6
Net income after dividends on preference stock	$	111.2		$	12.9		$	14.2		$	8.1

Operating Revenues

Operating revenues for 2009 were $1.3 billion, a decrease of $85.0 million from the previous year. The following table summarizes the significant changes in operating revenues for the past three years:

	Amount
	2009			2008			2007
	(in millions)
Retail — prior year	$	1,120.8		$	1,006.3		$	952.0
Estimated change in -
Rates and pricing		33.0			6.3			2.5
Sales growth (decline)		(5.7	)		(4.6	)		5.8
Weather		(4.5	)		3.9			1.2
Fuel and other cost recovery		(37.0	)		108.9			44.8
Retail — current year		1,106.6			1,120.8			1,006.3
Wholesale revenues -
Non-affiliates		94.1			97.1			83.5
Affiliates		32.1			107.0			113.2
Total wholesale revenues		126.2			204.1			196.7
Other operating revenues		69.4			62.3			56.8
Total operating revenues	$	1,302.2		$	1,387.2		$	1,259.8
Percent change		(6.1	)%		10.1	%		4.6	%

Retail revenues decreased $14.2 million, or 1.3%, in 2009, increased $114.4 million, or 11.4%, in 2008, and increased $54.3 million, or 5.7%, in 2007.

II-248

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Revenues associated with changes in rates and pricing include cost recovery provisions for energy conservation costs and environmental compliance costs. Annually, the Company petitions the Florida Public Service Commission (PSC) for recovery of projected costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment. See Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery” for additional information. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes relating to sales growth (or decline) and weather.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. Cost recovery provisions also include revenues related to the recovery of storm damage restoration costs. The recovery provisions generally equal the related expenses and have no material effect on net income. See Note 1 to the financial statements under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.

Total wholesale revenues were $126.2 million in 2009, a decrease of $77.8 million, or 38.2%, compared to 2008 primarily due to decreased energy sales to affiliates at a lower cost per kilowatt-hour (KWH). Total wholesale revenues were $204.1 million in 2008, an increase of $7.4 million, or 3.7%, compared to 2007 primarily due to higher capacity revenues associated with new and existing territorial wholesale contracts with non-affiliated companies. Total wholesale revenues were $196.7 million in 2007, a decrease of $8.5 million, or 4.2%, compared to 2006 primarily due to decreased energy sales to affiliates at a lower cost per KWH supplied by lower-cost generating resources.

Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy with the Southern Company service territory, and availability of Southern Company system generation.

Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to other Florida utilities. Wholesale revenues from contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy is generally sold at variable cost. The capacity and energy components under these unit power sales contracts were as follows:

	2009		2008		2007
	(in thousands)
Unit power sales -
Capacity	$	24,466	$	22,028	$	18,073
Energy		33,122		33,767		36,245
Total		57,588		55,795		54,318
Other power sales -
Capacity and other		11,060		10,890		2,397
Energy		25,457		30,380		26,799
Total		36,517		41,270		29,196
Total non-affiliated	$	94,105	$	97,065	$	83,514

Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand and the availability and cost of generating resources at each system company. These affiliated sales, along with purchases from affiliates, 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.

Other operating revenues increased $7.1 million, or 11.3%, in 2009 primarily due to other energy services and franchise fees, offset by transmission and distribution network services and timber sales. Other operating revenues increased $5.6 million, or 9.9%, in 2008 primarily due to transmission and distribution network services and other energy services. Other operating revenues increased $10.2 million, or 21.8%, in 2007 primarily due to other energy services and an increase in franchise fees. The increased revenues from other energy services did not have a material impact on earnings since they were generally offset by associated expenses. Franchise fees have no impact on net income.

II-249

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2009 and the percent change by year were as follows:

	KWHs		Percent Change
	2009		2009			2008			2007
	(in millions)
Residential		5,255		(1.8	)%		(2.3	)%		0.9	%
Commercial		3,896		(1.6	)		(0.3	)		3.3
Industrial		1,727		(21.9	)		7.9			(4.1	)
Other		25		8.1			(5.1	)		4.2
Total retail		10,903		(5.5	)		0.2			0.8
Wholesale
Non-affiliates		1,813		(0.2	)		(18.4	)		7.1
Affiliates		870		(53.5	)		(35.1	)		(1.8	)
Total wholesale		2,683		(27.2	)		(27.8	)		1.9
Total energy sales		13,586		(10.8	)		(8.4	)		1.1

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers.

Residential energy sales decreased 1.8% in 2009 compared to 2008 primarily due to the recessionary economy. Residential energy sales decreased 2.3% in 2008 compared to 2007 primarily due to decreased customer usage as a result of a slowing economy, partially offset by more favorable weather. Residential energy sales increased 0.9% in 2007 compared to 2006 primarily due to more favorable weather conditions and customer growth, partially offset by customer response to higher prices.

Commercial energy sales decreased 1.6% in 2009 compared to 2008 primarily due to the recessionary economy and a decrease in the number of customers. The change in commercial energy sales in 2008 compared to 2007 was immaterial. Commercial energy sales increased 3.3% in 2007 compared to 2006 primarily due to more favorable weather conditions and customer growth.

Industrial energy sales decreased 21.9% in 2009 compared to 2008 primarily due to increased customer co-generation due to the lower cost of natural gas in 2009, decreased demand, and a business closure due to the recessionary economy. Industrial energy sales increased 7.9% in 2008 compared to 2007 primarily due to decreased customer co-generation due to the higher cost of natural gas.Industrial energy sales decreased 4.1% in 2007 compared to 2006 primarily due to a conversion project by a major forest products manufacturer and a production process change by a major petroleum company.

Wholesale energy sales to non-affiliates decreased 0.2% in 2009, decreased 18.4% in 2008, and increased 7.1% in 2007, each compared to the prior year. The decrease in 2009 was primarily a result of the recessionary economy. The changes in 2008 and 2007 were primarily the result of fluctuations in the fuel cost to produce energy sold to non-affiliated utilities under both long-term and short-term contracts. The degree to which prices for oil and natural gas, 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 marginal cost.

Wholesale energy sales to affiliates decreased 53.5% in 2009, 35.1% in 2008, and 1.8% in 2007, compared to prior years. The decrease in 2009 was primarily a result of the recessionary economy. The decreases in 2008 and 2007 were primarily due to the availability of lower cost generation resources at affiliated companies.

II-250

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

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 generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

Details of the Company’s electricity generated and purchased were as follows:

	2009			2008			2007
Total generation(millions of KWHs)		12,895			14,762			16,657
Total purchased power(millions of KWHs)		1,481			1,187			798
Sources of generation(percent)-
Coal		69	%		84	%		86	%
Gas		31			16			14
Cost of fuel, generated(cents per net KWH)-
Coal		4.27			3.58			2.86
Gas		4.66			8.02			6.91
Average cost of fuel, generated(cents per net KWH)*		4.39			4.31			3.44
Average cost of purchased power(cents per net KWH)		6.71			9.21			8.96

* Fuel includes fuel purchased by the Company for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

Total fuel and purchased power expenses were $665.4 million in 2009, a decrease of $79.6 million, or 10.7%, below the prior year costs. The net decrease in fuel and purchased power expenses was primarily due to a $53.3 million decrease related to total KWHs generated and purchased and a $26.3 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas. Total fuel and purchased power expenses were $745.0 million in 2008, an increase of $100.1 million, or 15.5%, above the prior year costs. The net increase in fuel and purchased power expenses was due to a $130.5 million increase in the average cost of fuel and purchased power as well as a $34.9 million increase related to KWHs purchased, offset by a $65.3 million decrease related to KWHs generated. Total fuel and purchased power expenses were $644.9 million in 2007, an increase of $36.2 million, or 5.9%, above the prior year costs. The net increase in fuel and purchased power expenses was due to a $32.6 million increase in the average cost of fuel and purchased power as well as a $10.1 million increase related to KWHs generated, offset by a $6.5 million decrease related to KWHs purchased.

Fuel expense was $573.4 million in 2009, a decrease of $62.2 million, or 9.8%, below the prior year costs. This decrease was primarily the result of a 41.9% decrease in the average cost of natural gas and a 12.6% decrease in KWHs generated as a result of lower demand, partially offset by an increase of 19.3% in the average cost of coal per KWH generated. Fuel expense was $635.6 million in 2008, an increase of $62.2 million, or 10.9%, above the prior year costs. This increase was the result of a 25.3% increase in the average cost of fuel, offset by an 11.4% decrease in KWHs generated. Fuel expense was $573.4 million in 2007, an increase of $38.5 million, or 7.2%, above the prior year costs. This increase was the result of a 5.2% increase in the average cost of fuel and a 1.9% increase in KWHs generated.

Purchased power expense was $92.0 million in 2009, a decrease of $17.4 million, or 15.9%, below the prior year costs. This decrease was primarily the result of a 27.1% decrease in the average cost per KWH purchased, offset by a 24.8% increase in the volume of KWHs purchased. Purchased power expense was $109.4 million in 2008, an increase of $37.9 million, or 53.0%, above the prior year costs. This increase was the result of a 48.8% increase in total KWHs purchased and a 2.8% increase in the average cost per net KWH. Purchased power expense was $71.5 million in 2007, a decrease of $2.3 million, or 3.1%, below the prior year costs. This decrease was the result of an 8.9% decrease in total KWHs purchased, offset by a 6.3% increase in the average cost per net KWH.

Coal prices continued to be influenced by worldwide demand from developing countries, as well as increased mining and fuel transportation costs. While coal prices reached unprecedented high levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices did not fully offset the higher priced coal already in inventory and under long-term contract. Demand for natural gas in the United States also was affected by the recessionary economy leading to significantly lower natural gas prices.

Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.

II-251

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Other Operations and Maintenance Expenses

In 2009, other operations and maintenance expenses decreased $17.2 million, or 6.2%, compared to the prior year primarily due to a $14.4 million decrease in administrative and general expense, most of which is related to decreased storm recovery costs, and a $6.7 million decrease in power generation, most of which is related to scheduled and unscheduled maintenance and cost containment activities in an effort to offset the effects of the recessionary economy. This decrease was partially offset by a $4.8 million increase in other energy services. In 2008, other operations and maintenance expenses increased $7.1 million, or 2.6%, compared to the prior year primarily due to an $8.2 million increase in scheduled and unscheduled maintenance at generation facilities. In 2007, other operations and maintenance expenses increased $10.9 million, or 4.2%, compared to the prior year primarily due to a $5.0 million increase in other energy services and a $4.3 million increase in severance costs associated with a reorganization. The increased expenses from other energy services did not have a material impact on earnings since they were generally offset by associated revenue. In 2007, the Company offered both voluntary and involuntary severance to a number of employees in connection with a reorganization of certain functions.

Depreciation and Amortization

Depreciation and amortization expense increased $8.6 million, or 10.1%, in 2009 compared to the prior year primarily due to additions of environmental control projects at Plant Crist and Plant Scherer and other net additions to generation and distribution facilities. Depreciation and amortization expense decreased $0.8 million, or 0.9%, in 2008 compared to the prior year primarily as a result of a $3.8 million gain on the sale of a building. The decrease was partially offset by an increase of $3.0 million in depreciation due to net additions to generation and distribution facilities. Depreciation and amortization expense decreased $3.6 million, or 4.0%, in 2007 compared to the prior year primarily due to new depreciation rates implemented in January 2007.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $7.3 million, or 8.3%, in 2009 compared to the prior year primarily due to a $5.6 million increase in gross receipts and franchise taxes, which have no impact on net income, and a $1.6 million increase in property taxes. Taxes other than income taxes increased $4.2 million, or 5.1%, in 2008 compared to the prior year primarily due to a $1.9 million decrease in 2007 related to the resolution of a dispute regarding property taxes in Monroe County, Georgia and a $1.9 million increase in franchise and gross receipt taxes. Taxes other than income taxes increased $3.2 million, or 4.0%, in 2007 compared to the prior year primarily due to increases in franchise and gross receipts taxes.

Allowance for Funds Used During Construction Equity

AFUDC equity increased $13.8 million, or 138.8%, in 2009 compared to the prior year primarily due to construction of environmental control projects at Plant Crist and Plant Scherer. AFUDC equity increased $7.6 million, or 319.9%, in 2008 compared to the prior year primarily due to construction of environmental control projects at Plant Crist and Plant Scherer. AFUDC equity increased $2.0 million, or 554.0%, in 2007 compared to the prior year primarily due to construction of an environmental control project at Plant Crist. 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

Interest income decreased $2.7 million, or 86.6%, in 2009 compared to the prior year primarily due to decreases in interest received related to the recovery of financing costs associated with the fuel clause. Interest income decreased $2.2 million, or 41%, in 2008 primarily as a result of lower variable interest rates charged against the under recovered fuel balance and a decrease in the property damage reserve balance. Interest income increased $0.1 million, or 2.3%, in 2007 compared to the prior year primarily due to interest received related to the recovery of financing costs associated with the fuel clause and incurred costs for storm damage activity as approved by the Florida PSC. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein and Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $4.7 million, or 11.0%, in 2009 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects at Plant Crist and Plant Scherer. Interest expense, net of amounts capitalized decreased $1.6 million, or 3.5%, in 2008 compared to the prior year as the result of an increase in capitalization of AFUDC debt related to the construction of environmental control projects and the redemption of $41.2 million of long-term debt payable to an affiliated trust in 2007. These decreases were offset by the issuance of a $110 million term loan agreement in 2008. Interest expense, net of amounts capitalized increased $0.5 million, or 1.2%, in 2007 compared to the prior year and was not material.

Income Taxes

Income taxes decreased $1.1 million, or 2.0%, in 2009, compared to the prior year primarily due to the tax benefit associated with an increase in AFUDC, which is non-taxable, partially offset by higher earnings before taxes. Income taxes increased $7.0 million, or 14.9%, in 2008, compared to the prior year primarily due to higher earnings before income taxes and a decrease in the federal production activities deduction, partially offset by the tax benefit associated with an increase in AFUDC, which is non-taxable. Income taxes increased $1.8 million, or 4.0%, in 2007, compared to the prior year primarily as a result of higher earnings before income taxes. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial.

FUTURE EARNINGS POTENTIAL

General

The Company operates as a vertically integrated utility providing electricity to retail 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 wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated 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 for additional information about 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 Company’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining 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 or decline in the Company’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery will impact future earnings.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

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 Company (Alabama Power) and Georgia Power Company (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. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company’s Plant Crist. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the

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Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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; the Endangered Species Act; and related federal and state regulations. 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 2009, the Company had invested approximately $1.1 billion in capital projects to comply with these requirements, with annual totals of $343 million, $296 million, and $124 million for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $113 million, $195 million, and $194 million for 2010, 2011, and 2012, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, 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 2009, the Company had spent approximately $834 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are scheduled to be installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment under the eight-hour ozone standard. In March 2008, however, the

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EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to finalize the revised standard in August 2010 and require state implementation plans for any nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory.

During 2005, the EPA’s annual fine particulate matter nonattainment designations became effective for several areas within Georgia. State plans for addressing the nonattainment designations for this standard could require further reductions in SO₂ and NO_x emissions from power plants, including plants owned in part by the Company. On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard for SO₂. The EPA is expected to finalize the revised SO₂ standard in June 2010.

Twenty-eight eastern states, including the States of Florida, Georgia, and Mississippi, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The States of Florida, Georgia, and Mississippi have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in July 2010.

The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring 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) to certain sources built between 1962 and 1977, and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural conditions goal by 2018 and for each ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and NO_x, and no additional controls beyond CAIR are anticipated to be necessary at the Company’s facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress.

The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants, including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and trade program for the reduction of mercury emissions from coal-fired power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011, and a final rule by November 16, 2011.

The impacts of the eight-hour ozone standards, the fine particulate matter nonattainment designations, and future revisions to CAIR, the SO₂ standard, the Clean Air Visibility Rule, and the MACT rule for electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂and NO_x emissions controls within the next several years to ensure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is now in the process of revising the regulations. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on further rulemaking by the EPA and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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On December 28, 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions by 2013. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, 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 releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Included in this amount are costs associated with remediation of the Company’s substation sites. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause; therefore, there is no impact to the Company’s net income as a result of these liabilities. 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 Matters – Environmental Remediation” for additional information.

Coal Combustion Byproducts

The EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA has collected information from the electric utility industry on surface impoundment safety and conducted on-site inspections at three Southern Company system facilities as part of its evaluation. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010. The impact of these additional regulations on the Company will depend on the specific provisions of the final rule and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the Company’s management, beneficial use, and disposal of such byproducts and could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March

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2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 – BUSINESS – “Rate Matters – Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 14 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 11 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions.

PSC Matters

General

The Company’s rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company’s rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation, and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company’s base rates.

On November 2, 2009, the Florida PSC approved the Company’s annual rate requests for its purchased power capacity, energy conservation, and environmental compliance cost recovery factors for 2010. On December 1, 2009, the Florida PSC approved the Company’s annual rate request for its 2010 fuel cost recovery factor, which includes both fuel and purchased energy cost. The net effect of the approved changes to the Company’s cost recovery factors for 2010 is a 3.9% rate increase for residential customers using 1,000 KWHs per month. Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on the Company’s revenues or net income, but does impact annual cash flow. See Notes 1 and 3 to the financial statements under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively.

Fuel Cost Recovery

The Company petitions for fuel cost recovery rates to be approved by the Florida PSC on an annual basis. At December 31, 2009 and 2008, the under recovered balance was $2.4 million and $96.7 million, respectively. The change in 2009 was primarily due to an increase in the 2009 fuel cost recovery factors and resulting revenue collected in the period and a higher percentage of natural gas-fired generation which cost less than projected. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. If the projected fuel cost over or under recovery exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.

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Purchased Power Capacity Recovery

The Florida PSC allows the Company to recover its costs for capacity purchased from other power producers under power purchase agreements (PPAs) through a separate cost recovery component or factor in the Company’s retail energy rates. Like the other specific cost recovery factors included in the Company’s retail energy rates, the rates for purchased capacity are set annually on a calendar year basis. When the Company enters into a new PPA, it is reviewed and approved by the Florida PSC for cost recovery purposes. As of December 31, 2009 and 2008, the Company had an over recovered purchased power capacity balance of approximately $1.5 million and $0.3 million, respectively, which is included in other regulatory liabilities, current in the balance sheets.

In March 2009, the Company entered into a PPA (the Agreement) with Shell Energy North America (US), L.P. (Shell) conditioned on subsequent review and approval of the Company’s participation by the Florida PSC. The Florida PSC approved the Agreement through an order that became final in October 2009. As a result, the Agreement became effective on November 1, 2009. The Agreement will terminate on May 24, 2023, unless terminated earlier in accordance with its terms. Under the terms of the Agreement, the Company will be entitled to all of the capacity and energy from an approximately 885 MW combined cycle power plant (the Plant) located in Autauga County, Alabama that is owned and operated by Tenaska Alabama II Partners, L.P. (Tenaska). Shell is entitled to all of the capacity and energy from the Plant under a 20-year Energy Conversion Agreement between Shell and Tenaska that expires on May 24, 2023. Payments under the Agreement will be material. However, these costs have been approved by the Florida PSC for recovery through the Company’s fuel clause and purchased power capacity clause; therefore, no material impact is expected on the Company’s net income. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein and Note 7 to the financial statements under “Fuel and Purchased Power Commitments” for additional information.

Environmental Cost Recovery

In August 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed in March 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. On April 1, 2009, the Company filed an update to the plan, which was approved by the Florida PSC on November 2, 2009. The Florida PSC acknowledged that the costs associated with the Company’s CAIR and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause. Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2009 and 2008, the over recovered environmental balance was approximately $11.7 million and $71 thousand, respectively, which is included in other regulatory liabilities, current in the balance sheets. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein, Note 3 to the financial statements under “Retail Regulatory Matters – Environmental Cost Recovery,” and Note 7 to the financial statements under “Construction Program” for additional information.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of the Company. The Company’s cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA was approximately $19 million. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of the Company.

On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $15.5 million relates to the Company, under the ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. The Company continues to assess the other financial implications of the ARRA.

The U.S. House of Representatives and the U.S. Senate have passed separate bills related to healthcare reform. Both bills include a provision that would make Medicare Part D subsidy reimbursements taxable. If enacted into law, this provision could have a significant negative impact on the Company’s net income. See Note 2 to the financial statements under “Other Postretirement Benefits” for additional information.

The ultimate impact of these matters cannot be determined at this time.

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Income Tax Matters

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Other Matters

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

The Company is subject to retail regulation by the Florida PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require 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 the accounting standards 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

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to such risks and, in accordance with generally accepted accounting principles (GAAP), records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters.

• Changes in existing income tax regulations or changes in IRS or state revenue department 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 new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA.

Unbilled Revenues

Revenues related to the retail 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.

Pension and Other Postretirement Benefits

The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that considers external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption would result in a $0.8 million or less change in total benefit expense and a $12 million or less change in projected obligations.

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New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted this new guidance effective January 1, 2010, with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2009. Throughout the turmoil in the financial markets, the Company has maintained adequate access to capital without drawing on any of its bank credit arrangements used to support its commercial paper program and variable rate pollution control revenue bonds. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit increased in 2009, and the Company may continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees for the Company average less than³/4 of 1% per year. See “Sources of Capital” and “Financing Activities” herein for additional information.

The Company’s investments in pension trust funds remained stable in value as of December 31, 2009. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities totaled $194.2 million, $147.9 million, and $217.0 million for 2009, 2008, and 2007, respectively. The $46.3 million increase in net cash provided from operating activities in 2009 was primarily due to a $134.5 million reduction in accounts receivable related to fuel cost, partially offset by a $40.5 million decrease in deferred income taxes and a $38.4 million increase in fuel inventory. The $69.1 million decrease in net cash provided from operating activities in 2008 was due primarily to a $61.0 million increase in cash used for the under recovered regulatory clause related to fuel. The $73.6 million increase in net cash provided from operating activities in 2007 was due primarily to increased cash inflows for fuel cost recovery.

Net cash used for investing activities totaled $468.4 million, $348.7 million, and $239.3 million for 2009, 2008, and 2007, respectively. The increases in cash used for investing activities were primarily due to gross property additions to utility plant of $450.4 million, $390.7 million, and $239.3 million for 2009, 2008, and 2007, respectively. Funds for the Company’s property additions were provided by operating activities, capital contributions, and other financing activities.

Net cash provided from financing activities totaled $279.4 million, $198.8 million, and $20.2 million for 2009, 2008, and 2007, respectively. The $80.6 million increase in net cash provided from financing activities in 2009 was due primarily to $258.4 million in debt issuances and cash raised from a common stock sale, partially offset by a $157.0 million decrease in notes payable. The $178.6 million increase in net cash provided from financing activities in 2008 was due primarily to the issuance of $110 million in long-term debt and $50 million in short-term debt, and a $49.1 million change in commercial paper cash flows in 2008. The increase was partially offset by the issuance of $85 million in senior notes in 2007. The $4.5 million decrease in net cash provided from financing activities in 2007 was due primarily to a $105.6 million change in commercial paper cash flows and a $25.0 million decrease in senior note proceeds. These decreases were partially offset by the issuance of $80 million in common stock and $45 million in preference stock in 2007.

Significant balance sheet changes in 2009 include an increase of $374.1 million in total property, plant, and equipment, primarily related to environmental control projects; the issuance of $140.0 million in senior notes; the issuance of common stock to Southern Company for $135.0 million; the issuance of $130.4 million of pollution control revenue bonds, with a related restricted cash balance of $6.3 million; an increase in fossil fuel stock of $75.5 million; an increase in customer accounts receivable and unbilled revenues of $6.4 million; and a $94.4 million decrease in under recovered regulatory clause revenues primarily related to fuel.

II-262

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

The Company’s ratio of common equity to total capitalization, including short-term debt, was 43.4% in 2009, 42.9% in 2008, and 45.3% in 2007. See Note 6 to the financial statements for additional information.

The Company has received investment grade credit ratings from the major rating agencies with respect to its debt and preference stock. See SELECTED FINANCIAL AND OPERATING DATA and “Credit Rating Risk” herein for additional information regarding the Company’s security ratings.

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, security issuances, term loans, and short-term indebtedness. However, the type and timing of any future financings, if needed, will depend on market conditions, regulatory approval, and other factors.

Security issuances are 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 (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts, if any, 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 has various internal and external sources of liquidity. At December 31, 2009, the Company had approximately $9 million of cash and cash equivalents, along with $220 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire in 2010 and $70 million contain provisions allowing one-year term loans executable at expiration. The Company plans to renew these lines of credit during 2010 prior to their expiration. In addition, the Company has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, 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 at the request and for the benefit of the Company and the other traditional 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 traditional operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2009, the Company had $88.9 million of commercial paper outstanding. At December 31, 2009, the Company also had $1.4 million in notes payable outstanding related to other energy services contracts.

Financing Activities

In 2009, the Company issued $140 million of senior notes and incurred obligations related to the issuance of $130.4 million of pollution control revenue bonds. In addition, the Company issued to Southern Company 1,350,000 shares of the Company’s common stock, without par value, and realized proceeds of $135 million. On January 25, 2010, the Company issued to Southern Company 500,000 shares of the Company’s common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company’s short-term debt, to fund construction of certain environmental projects, and for other general corporate purposes, including the Company’s continuous construction program.

The Company also entered into forward starting interest rate swaps during 2009 totaling $100 million to mitigate exposure to interest rate changes related to anticipated debt issuances. The swaps have been designated as cash flow hedges.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery, 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, emissions allowances, and energy price risk management. At December 31, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $130 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $547 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

On September 2, 2009, Moody’s Investors Service (Moody’s) affirmed the credit ratings of the Company’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On September 4, 2009, Fitch Ratings, Inc. affirmed the Company’s senior unsecured notes and commercial paper ratings of A/F1, respectively, and maintained a stable rating outlook for the Company. On October 6, 2009, Standard and Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc. (S&P) affirmed the credit ratings of the Company’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook.

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, where possible, 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 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 financial hedge contracts for natural gas purchases. The Company has implemented a fuel-hedging program per the guidelines of the Florida PSC.

The weighted average interest rate on $319 million variable rate long-term debt at January 1, 2010 was 0.45%. 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 $3 million at January 1, 2010. See Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements for additional information.

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

	2009			2008
	Changes			Changes
	Fair Value
	(in thousands)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(31,161	)	$	(202	)
Contracts realized or settled		41,683			(7,960	)
Current period changes(a)		(24,209	)		(22,999	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(13,687	)	$	(31,161	)

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

The change in the fair value positions of the energy-related derivative contracts for the year-ended December 31, 2009 was an increase of $17.5 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and prices of natural gas. At December 31, 2009, the Company had a net hedge volume of 11.0 million mmBtu with a weighted average contract cost approximately $1.26 per mmBtu above market prices, and 14.2 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.24 per mmBtu above market prices. Natural gas settlements are recovered through the fuel cost recovery clause.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/ (liabilities) as follows:

Asset (Liability) Derivatives	2009			2008
	(in thousands)
Regulatory hedges	$	(13,699	)	$	(31,161	)
Not designated		12			—
Total fair value	$	(13,687	)	$	(31,161	)

Energy-related derivative contracts designated as regulatory hedges are related to the Company’s fuel hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Unrealized pre-tax gains and losses from energy-related derivative contracts recognized in income were not material for any year presented.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total						Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in thousands)
Level 1	$	—		$	—		$	—		$	—
Level 2		(13,687	)		(9,288	)		(4,264	)		(135	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(13,687	)	$	(9,288	)	$	(4,264	)	$	(135	)

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 9 to the financial statements for further discussion on fair value measurement.

The Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P 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 Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements for additional information.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $271.4 million in 2010, $350.2 million in 2011, and $418.5 million in 2012. Environmental expenditures included in these estimated amounts are $113.4 million in 2010, $194.8 million in 2011, and $194.2 million in 2012. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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 FERC and the Florida PSC.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preference stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, 7, and 10 to the financial statements for additional information.

II-265

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(d)		Total
	(in thousands)
Long-term debt(a) –
Principal	$	140,000	$	110,000	$	135,000	$	740,441	$	—	$	1,125,441
Interest		41,237		80,746		77,388		464,144		—		663,515
Energy-related derivative obligations(b)		9,442		4,264		183		—		—		13,889
Preference stock dividends(c)		6,203		12,405		12,405		—		—		31,013
Operating leases		14,525		20,539		12,793		1,613		—		49,470
Unrecognized tax benefits and interest(d)		—		—		—		—		1,729		1,729
Purchase commitments(e) –
Capital(f)		271,419		768,706		—		—		—		1,040,125
Limestone(g)		6,043		12,543		13,178		35,938		—		67,702
Coal		515,241		75,561		—		—		—		590,802
Natural gas(h)		112,080		137,566		101,176		130,889		—		481,711
Purchased power(i)		39,432		82,474		97,317		659,261		—		878,484
Long-term service agreements(j)		6,315		13,303		13,977		25,583		—		59,178
Postretirement benefits trust(k)		54		107		—		—		—		161
Total	$	1,161,991	$	1,318,214	$	463,417	$	2,057,869	$	1,729	$	5,003,220

(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, 2010, as reflected in the statements of capitalization.
(b)	For additional information, see Notes 1 and 10 to the financial statements.
(c)	Preference stock does not mature; therefore, amounts are provided for the next five years only.
(d)	The timing related to the realization of $1.7 million in unrecognized tax benefits and interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information.
(e)	The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2009, 2008, and 2007 were $260 million, $277 million, and $270 million, respectively.
(f)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program.
(g)	As part of the Company’s program to reduce sulfur dioxide emissions from its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment.
(h)	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, 2009.
(i)	The capacity-related costs associated with PPAs are recovered through the purchased power capacity costs recovery clause. See Notes 3 and 7 to the financial statements for additional information.
(j)	Long-term service agreements include price escalation based on inflation indices.
(k)	The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant. The projections of the amount vary significantly depending on key variables, including future trust fund performance, and cannot be determined at this time; therefore, no amounts related to the pension trust fund are included in the table. 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-266

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, earnings growth, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, start and completion of construction projects, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances, and also changes in 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 EPA civil actions against the Company;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

• variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population, and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• 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 actions relating to fuel and other cost recovery mechanisms;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

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

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

II-267

STATEMENTS OF INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Gulf Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Revenues:
Retail revenues	$	1,106,568		$	1,120,766		$	1,006,329
Wholesale revenues, non-affiliates		94,105			97,065			83,514
Wholesale revenues, affiliates		32,095			106,989			113,178
Other revenues		69,461			62,383			56,787
Total operating revenues		1,302,229			1,387,203			1,259,808
Operating Expenses:
Fuel		573,407			635,634			573,354
Purchased power, non-affiliates		23,706			29,590			11,994
Purchased power, affiliates		68,276			79,750			59,499
Other operations and maintenance		260,274			277,478			270,440
Depreciation and amortization		93,398			84,815			85,613
Taxes other than income taxes		94,506			87,247			82,992
Total operating expenses		1,113,567			1,194,514			1,083,892
Operating Income		188,662			192,689			175,916
Other Income and (Expense):
Allowance for equity funds used during construction		23,809			9,969			2,374
Interest income		423			3,155			5,348
Interest expense, net of amounts capitalized		(38,358	)		(43,098	)		(44,680	)
Other income (expense), net		(4,075	)		(4,064	)		(3,876	)
Total other income and (expense)		(18,201	)		(34,038	)		(40,834	)
Earnings Before Income Taxes		170,461			158,651			135,082
Income taxes		53,025			54,103			47,083
Net Income		117,436			104,548			87,999
Dividends on Preference Stock		6,203			6,203			3,881
Net Income After Dividends on Preference Stock	$	111,233		$	98,345		$	84,118

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

II-268

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009, 2008, and 2007
Gulf Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Activities:
Net income	$	117,436		$	104,548		$	87,999
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		99,564			93,607			90,694
Deferred income taxes		(16,545	)		23,949			(10,818	)
Allowance for equity funds used during construction		(23,809	)		(9,969	)		(2,374	)
Pension, postretirement, and other employee benefits		1,769			1,585			6,062
Stock based compensation expense		933			765			1,141
Tax benefit of stock options		17			215			344
Hedge settlements		—			(5,220	)		3,030
Other, net		(5,190	)		(5,149	)		(7,072	)
Changes in certain current assets and liabilities —
-Receivables		83,245			(49,886	)		10,301
-Fossil fuel stock		(75,145	)		(36,765	)		5,025
-Materials and supplies		(1,642	)		8,927			(2,625	)
-Prepaid income taxes		(6,355	)		(416	)		7,177
-Property damage cost recovery		10,746			26,143			25,103
-Other current assets		(204	)		(307	)		(632	)
-Accounts payable		7,890			(4,561	)		(556	)
-Accrued taxes		(2,404	)		(6,511	)		4,773
-Accrued compensation		(6,330	)		570			(1,322	)
-Other current liabilities		10,255			6,417			732
Net cash provided from operating activities		194,231			147,942			216,982
Investing Activities:
Property additions		(421,309	)		(377,790	)		(241,538	)
Investment in restricted cash from pollution control revenue bonds		(49,188	)		—			—
Distribution of restricted cash from pollution control revenue bonds		42,841			—			—
Cost of removal net of salvage		(9,751	)		(8,713	)		(9,408	)
Construction payables		(23,603	)		37,244			10,817
Other investing activities		(7,426	)		576			803
Net cash used for investing activities		(468,436	)		(348,683	)		(239,326	)
Financing Activities:
Increase (decrease) in notes payable, net		(49,599	)		107,438			(75,820	)
Proceeds —
Common stock issued to parent		135,000			—			80,000
Capital contributions from parent company		22,032			75,324			4,174
Gross excess tax benefit of stock options		51			298			799
Preference stock		—			—			45,000
Pollution control revenue bonds		130,400			37,000			—
Senior notes		140,000			—			85,000
Other long-term debt issuances		—			110,000			—
Redemptions —
Pollution control revenue bonds		—			(37,000	)		—
Senior notes		(1,214	)		(1,300	)		—
Other long-term debt		—			—			(41,238	)
Payment of preference stock dividends		(6,203	)		(6,057	)		(3,300	)
Payment of common stock dividends		(89,300	)		(81,700	)		(74,100	)
Other financing activities		(1,728	)		(5,167	)		(349	)
Net cash provided from financing activities		279,439			198,836			20,166
Net Change in Cash and Cash Equivalents		5,234			(1,905	)		(2,178	)
Cash and Cash Equivalents at Beginning of Year		3,443			5,348			7,526
Cash and Cash Equivalents at End of Year	$	8,677		$	3,443		$	5,348
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $9,489, $3,973 and $1,048 capitalized, respectively)	$	40,336		$	39,956		$	35,237
Income taxes (net of refunds)		73,889			40,176			39,228
Non-cash decrease in notes payable related to energy services		(8,309	)		—			—

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

II-269

BALANCE SHEETS
At December 31, 2009 and 2008
Gulf Power Company 2009 Annual Report

Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	8,677		$	3,443
Restricted cash and cash equivalents		6,347			—
Receivables —
Customer accounts receivable		64,257			69,531
Unbilled revenues		60,414			48,742
Under recovered regulatory clause revenues		4,285			98,644
Other accounts and notes receivable		4,107			7,201
Affiliated companies		7,503			8,516
Accumulated provision for uncollectible accounts		(1,913	)		(2,188	)
Fossil fuel stock, at average cost		183,619			108,129
Materials and supplies, at average cost		38,478			36,836
Other regulatory assets, current		19,172			38,908
Prepaid expenses		44,760			20,363
Other current assets		3,634			5,292
Total current assets		443,340			443,417
Property, Plant, and Equipment:
In service		3,430,503			2,785,561
Less accumulated provision for depreciation		1,009,807			971,464
Plant in service, net of depreciation		2,420,696			1,814,097
Construction work in progress		159,499			391,987
Total property, plant, and equipment		2,580,195			2,206,084
Other Property and Investments		15,923			15,918
Deferred Charges and Other Assets:
Deferred charges related to income taxes		39,018			24,220
Other regulatory assets, deferred		190,971			170,836
Other deferred charges and assets		24,160			18,550
Total deferred charges and other assets		254,149			213,606
Total Assets	$	3,293,607		$	2,879,025

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

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BALANCE SHEETS
At December 31, 2009 and 2008
Gulf Power Company 2009 Annual Report

Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	140,000	$	—
Notes payable		90,331		148,239
Accounts payable —
Affiliated		47,421		50,304
Other		80,184		90,381
Customer deposits		32,361		28,017
Accrued taxes —
Accrued income taxes		1,955		39,983
Other accrued taxes		7,297		11,855
Accrued interest		10,222		8,959
Accrued compensation		9,337		15,667
Other regulatory liabilities, current		22,416		4,602
Liabilities from risk management activities		9,442		26,928
Other current liabilities		20,092		29,047
Total current liabilities		471,058		453,982
Long-Term Debt(See accompanying statements)		978,914		849,265
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		297,405		254,354
Accumulated deferred investment tax credits		9,652		11,255
Employee benefit obligations		109,271		97,389
Other cost of removal obligations		191,248		180,325
Other regulatory liabilities, deferred		41,399		28,597
Other deferred credits and liabilities		92,370		83,768
Total deferred credits and other liabilities		741,345		655,688
Total Liabilities		2,191,317		1,958,935
Preference Stock(See accompanying statements)		97,998		97,998
Common Stockholder’s Equity(See accompanying statements)		1,004,292		822,092
Total Liabilities and Stockholder’s Equity	$	3,293,607	$	2,879,025
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, 2009 and 2008
Gulf Power Company 2009 Annual Report

	2009			2008			2009			2008
	(in thousands)						(percent of total)
Long Term Debt:
Long-term notes payable —
4.35% due 2013		60,000			60,000
4.90% due 2014		75,000			75,000
5.25% to 5.90% due 2016-2044		452,486			453,700
Variable rates (0.35% at 1/1/10) due 2010		140,000			—
Variable rates (0.68% at 1/1/10) due 2011		110,000			110,000
Total long-term notes payable		837,486			698,700
Other long-term debt —
Pollution control revenue bonds —
1.50% to 6.00% due 2022-2039		218,625			153,625
Variable rates (0.25% to 0.28% at 1/1/10) due 2022-2039		69,330			3,930
Total other long-term debt		287,955			157,555
Unamortized debt discount		(6,527	)		(6,990	)
Total long-term debt (annual interest requirement — $41.2 million)		1,118,914			849,265
Less amount due within one year		140,000			—
Long-term debt excluding amount due within one year		978,914			849,265			47.0	%		48.0	%
Preferred and Preference Stock:
Authorized - 20,000,000 shares—preferred stock
- 10,000,000 shares—preference stock
Outstanding - $100 par or stated value — 6% preference stock		53,886			53,886
— 6.45% preference stock		44,112			44,112
- 1,000,000 shares (non-cumulative)
Total preference stock (annual dividend requirement — $6.2 million)		97,998			97,998			4.7			5.5
Common Stockholder’s Equity:
Common stock, without par value —
Authorized - 20,000,000 shares
Outstanding - 2009: 3,142,717 shares
Outstanding - 2008: 1,792,717 shares		253,060			118,060
Paid-in capital		534,577			511,547
Retained earnings		219,117			197,417
Accumulated other comprehensive income (loss)		(2,462	)		(4,932	)
Total common stockholder’s equity		1,004,292			822,092			48.3			46.5
Total Capitalization	$	2,081,204		$	1,769,355			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, 2009, 2008, and 2007
Gulf Power Company 2009 Annual Report

	Number of										Accumulated
	Common										Other
	Shares		Common		Paid-In			Retained			Comprehensive
	Issued		Stock		Capital			Earnings			Income (Loss)			Total
	(in thousands)
Balance at December 31, 2006		993	$	38,060	$	428,592		$	171,968		$	(4,597	)	$	634,023
Net income after dividends on preference stock		—		—		—			84,118			—			84,118
Issuance of common stock		800		80,000		—			—			—			80,000
Capital contributions from parent company		—		—		6,457			—			—			6,457
Other comprehensive income (loss)		—		—		—			—			798			798
Cash dividends on common stock		—		—		—			(74,100	)		—			(74,100	)
Other		—		—		(41	)		—			—			(41	)
Balance at December 31, 2007		1,793		118,060		435,008			181,986			(3,799	)		731,255
Net income after dividends on preference stock		—		—		—			98,345			—			98,345
Capital contributions from parent company		—		—		76,539			—			—			76,539
Other comprehensive income (loss)		—		—		—			—			(1,133	)		(1,133	)
Cash dividends on common stock		—		—		—			(81,700	)		—			(81,700	)
Change in benefit plan measurement date		—		—		—			(1,214	)		—			(1,214	)
Balance at December 31, 2008		1,793		118,060		511,547			197,417			(4,932	)		822,092
Net income after dividends on preference stock		—		—		—			111,233			—			111,233
Issuance of common stock		1,350		135,000		—			—			—			135,000
Capital contributions from parent company		—		—		23,030			—			—			23,030
Other comprehensive income (loss)		—		—		—			—			2,470			2,470
Cash dividends on common stock		—		—		—			(89,300	)		—			(89,300	)
Other		—		—		—			(233	)		—			(233	)
Balance at December 31, 2009		3,143	$	253,060	$	534,577		$	219,117		$	(2,462	)	$	1,004,292

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

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STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Gulf Power Company 2009 Annual Report

	2009		2008			2007
			(in thousands)
Net income after dividends on preference stock	$	111,233	$	98,345		$	84,118
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1,132, $(1,077), and $232, respectively		1,803		(1,716	)		370
Reclassification adjustment for amounts included in net income, net of tax of $419, $366, and $269, respectively		667		583			428
Total other comprehensive income (loss)		2,470		(1,133	)		798
Comprehensive Income	$	113,703	$	97,212		$	84,916

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

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NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2009 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 four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), the Company, and Mississippi Power Company (Mississippi Power), are vertically integrated utilities providing electric service in four Southeastern states. The Company provides retail service to customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

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

The Company is subject to regulation by the Federal Energy Regulatory Commission (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, digital wireless communications, and other services with respect to business and operations and power pool operations. Costs for these services amounted to $87 million, $86 million, and $73 million during 2009, 2008, and 2007, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission (SEC) prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

The Company has agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $3.9 million, $8.1 million, and $5.1 million, and Mississippi Power $20.9 million, $22.8 million, and $23.1 million in 2009, 2008, and 2007, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information.

The Company entered into a power purchase agreement (PPA), with Southern Power for a total of approximately 292 megawatts (MWs) annually from June 2009 through May 2014. The PPA was the result of a competitive request for proposal process initiated by the Company in January 2006 to address the anticipated need for additional capacity beginning in 2009. In May 2007, the Florida PSC issued an order approving the PPA for the purpose of cost recovery through the Company’s purchased power capacity clause. The PPA with Southern Power was approved by the FERC in July 2007.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. There were no significant services provided or received in 2009, 2008, or 2007.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

The traditional 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 and Purchased Power Commitments” for additional information.

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate 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:

	2009			2008			Note
	(in thousands)
Deferred income tax charges	$	39,018		$	24,220			(a	)
Asset retirement obligations		(4,371	)		(4,531	)		(a,i	)
Other cost of removal obligations		(191,248	)		(180,325	)		(a	)
Deferred income tax credits		(11,412	)		(12,983	)		(a	)
Loss on reacquired debt		14,599			16,248			(b	)
Vacation pay		8,120			7,991			(c,i	)
Under recovered regulatory clause revenues		2,384			96,731			(d	)
Over recovered regulatory clause revenues		(14,510	)		(3,295	)		(d	)
Property damage reserve		(24,046	)		(9,801	)		(e	)
Fuel-hedging (realized and unrealized) losses		15,367			35,333			(f,i	)
Fuel-hedging (realized and unrealized) gains		(190	)		(1,071	)		(f,i	)
PPA charges		8,141			—			(i,j	)
Generation site selection/evaluation costs		8,373			2,370			(k	)
Other assets		131			990			(d,i	)
Environmental remediation		65,223			66,812			(g,i	)
PPA credits		(7,536	)		—			(i,j	)
Other liabilities		(715	)		(1,518	)		(d	)
Underfunded retiree benefit plans		91,055			81,912			(h,i	)
Total assets (liabilities), net	$	(1,617	)	$	119,083

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	Asset retirement and removal assets and liabilities are recovered, deferred charges related to income tax assets are recovered, and deferred charges related to income tax liabilities are amortized over the related property lives, which may range up to 65 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)	Recorded as earned by employees and recovered as paid, generally within one year.
(d)	Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.
(e)	Recorded and recovered or amortized as approved by the Florida PSC. The storm cost recovery surcharge ended in June 2009.
(f)	Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
(g)	Recovered through the environmental cost recovery clause when the remediation is performed.
(h)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
(i)	Not earning a return as offset in rate base by a corresponding asset or liability.
(j)	Recovered over the life of the PPA for periods up to 14 years.
(k)	Deferred pursuant to Florida Statute while the Company continues to evaluate certain potential new generation projects.

In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income 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 values. All regulatory assets and liabilities are to be reflected in rates.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

Revenues

Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. The Company’s retail electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. 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 projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under “Retail Regulatory Matters” for additional information.

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used.

Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

Property, Plant, and Equipment

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

The Company’s property, plant, and equipment consisted of the following at December 31:

	2009		2008
	(in thousands)
Generation	$	2,034,826	$	1,445,095
Transmission		317,298		305,097
Distribution		938,393		900,793
General		136,934		131,269
Plant acquisition adjustment		3,052		3,307
Total plant in service	$	3,430,503	$	2,785,561

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.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1% in 2009, 3.4% in 2008, and 3.4% in 2007. 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 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.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. The Company has received an order 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 are reflected in the balance sheets as a regulatory liability.

The liability recognized to retire long-lived assets primarily relates to the Company’s combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. 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 in accordance with accounting standards related to asset retirement and environmental obligations 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:

	2009			2008
	(in thousands)
Balance beginning of year	$	12,042		$	11,942
Liabilities incurred		224			—
Liabilities settled		(300	)		(354	)
Accretion		642			631
Cash flow revisions		—			(177	)
Balance end of year	$	12,608		$	12,042

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC, which 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. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 7.65%, 7.65%, and 7.48%, respectively, for the years 2009, 2008, and 2007. AFUDC, net of taxes, as a percentage of net income after dividends on preference stock was 26.64%, 12.62%, and 3.59%, respectively, for 2009, 2008, and 2007.

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

II-278

NOTES (continued)
Gulf Power Company 2009 Annual Report

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.

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 costs of such damage are 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 $3.5 million in 2009, $3.5 million in 2008, and $3.5 million in 2007. As of December 31, 2009 and 2008, the balance in the Company’s property damage reserve totaled approximately $24.0 million and $9.8 million, respectively, which is included in deferred liabilities in the balance sheets.

When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. Such a surcharge was authorized in 2005 after Hurricane Ivan in 2004 and was extended by a 2006 Florida PSC order approving a stipulation to address costs incurred as a result of Hurricanes Dennis and Katrina in 2005. According to the 2006 Florida PSC order, in the case of future storms, if the Company incurs cumulative costs for storm-recovery activities in excess of $10 million during any calendar year, the Company will be permitted to file a streamlined formal request for an interim surcharge. Any interim surcharge would provide for the recovery, subject to refund, of up to 80% of the claimed costs for storm-recovery activities. The Company would then petition the Florida PSC for full recovery through a final or non-interim surcharge or other cost recovery mechanism.

Injuries and Damages Reserve

The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, 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. The injuries and damages reserve was $2.9 million and $2.5 million at December 31, 2009 and 2008, respectively. For 2009, $1.6 million and $1.3 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2008, $2.5 million is included in current liabilities in the balance sheets. Liabilities in excess of the reserve balance of $0.1 million and $0.8 million at December 31, 2009 and 2008, respectively, are included in deferred credits and other liabilities in the balance sheets. Corresponding regulatory assets of $0.1 million and $0.8 million at December 31, 2009 and 2008, respectively, are included in current 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, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered through fuel cost recovery rates approved by the Florida PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

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 (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 9 for additional information. 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 (OCI) 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. See Note 10 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2009.

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.

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 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). No contributions to the defined benefit plan are expected for the year ending December 31, 2010. The Company also provides a defined benefit pension plan for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the FERC. For the year ending December 31, 2010, postretirement trust contributions are expected to total approximately $54,000.

The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to accounting standards related to defined postretirement benefit plans, the Company was required to change the measurement date for its defined postretirement benefit plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the Company adopted the measurement date provisions effective January 1, 2008 resulting in an increase in long-term liabilities of $1.4 million and an increase in prepaid pension costs of approximately $0.6 million.

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Pension Plans

The total accumulated benefit obligation for the pension plans was $275 million in 2009 and $243 million in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as follows:

	2009			2008
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	260,765		$	251,781
Service cost		6,478			8,437
Interest cost		17,139			19,344
Benefits paid		(12,884	)		(15,880	)
Plan amendments		—			—
Actuarial loss (gain)		27,388			(2,917	)
Balance at end of year		298,886			260,765
Change in plan assets
Fair value of plan assets at beginning of year		229,407			345,398
Actual return (loss) on plan assets		36,840			(101,036	)
Employer contributions		696			925
Benefits paid		(12,884	)		(15,880	)
Fair value of plan assets at end of year		254,059			229,407
Accrued liability	$	(44,827	)	$	(31,358	)

At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension plans were $284 million and $15 million, respectively. All pension plan assets are related to the qualified pension 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). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

The actual composition of the Company’s pension plan assets as of December 31, 2009 and 2008, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		29	%		33	%		34	%
International equity		28			29			23
Fixed income		15			15			14
Special situations		3			—			—
Real estate investments		15			13			19
Private equity		10			10			10
Total		100	%		100	%		100	%

The investment strategy for plan assets related to the Company’s defined benefit plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual

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asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable
	Assets			Inputs			Inputs
As of December 31, 2009:	(Level 1)			(Level 2)			(Level 3)		Total
				(in thousands)
Assets:
Domestic equity*	$	50,434		$	20,856		$	—	$	71,290
International equity*		65,197			6,497			—		71,694
Fixed income:
U.S. Treasury, government, and agency bonds		—			18,783			—		18,783
Mortgage- and asset-backed securities		—			5,107			—		5,107
Corporate bonds		—			12,589			—		12,589
Pooled funds		—			455			—		455
Cash equivalents and other		126			15,396			—		15,522
Special situations		—			—			—		—
Real estate investments		7,862			—			24,699		32,561
Private equity		—			—			25,053		25,053
Total	$	123,619		$	79,683		$	49,752	$	253,054
Liabilities:
Derivatives		(202	)		(51	)		—		(253	)
Total	$	123,417		$	79,632		$	49,752	$	252,801

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	47,250		$	19,242	$	—	$	66,492
International equity*		42,508			3,909		—		46,417
Fixed income:
U.S. Treasury, government, and agency bonds		—			19,866		—		19,866
Mortgage- and asset-backed securities		—			9,413		—		9,413
Corporate bonds		—			12,882		—		12,882
Pooled funds		—			139		—		139
Cash equivalents and other		994			9,089		—		10,083
Special situations		—			—		—		—
Real estate investments		6,476			—		37,790		44,266
Private equity		—			—		22,063		22,063
Total	$	97,228		$	74,540	$	59,853	$	231,621
Liabilities:
Derivatives		(348	)		—		—		(348	)
Total	$	96,880		$	74,540	$	59,853	$	231,273

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate			Private		Real Estate			Private
	Investments			Equity		Investments			Equity
	(in thousands)					(in thousands)
Beginning balance	$	37,790		$	22,063	$	47,025		$	23,400
Actual return on investments:
Related to investments held at year end		(10,741	)		1,724		(7,615	)		(6,332	)
Related to investments sold during the year		(2,938	)		452		180			1,125
Total return on investments		(13,679	)		2,176		(7,435	)		(5,207	)
Purchases, sales, and settlements		588			814		(1,800	)		3,870
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	24,699		$	25,053	$	37,790		$	22,063

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable in an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued utilizing matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships

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are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s pension plans consist of the following:

	2009			2008
	(in thousands)
Other regulatory assets, deferred	$	85,194		$	71,990
Other, current liabilities		(910	)		(863	)
Employee benefit obligations		(43,917	)		(30,495	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2010.

	Prior Service Cost		Net (Gain) Loss
	(in thousands)
Balance at December 31, 2009:
Regulatory assets	$	8,506	$	76,688
Balance at December 31, 2008:
Regulatory assets	$	9,984	$	62,006
Estimated amortization in net periodic pension cost in 2010:
Regulatory assets	$	1,302	$	398

The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory			Regulatory
	Assets			Liabilities
	(in thousands)
Balance at December 31, 2007	$	6,561		$	(60,464	)
Net loss (gain)		66,170			61,989
Change in prior service costs		—			—
Reclassification adjustments:
Amortization of prior service costs		(323	)		(1,525	)
Amortization of net gain		(418	)		—
Total reclassification adjustments		(741	)		(1,525	)
Total change		65,429			60,464
Balance at December 31, 2008	$	71,990		$	—
Net loss (gain)		14,906			—
Change in prior service costs		—			—
Reclassification adjustments:
Amortization of prior service costs		(1,478	)		—
Amortization of net gain		(224	)		—
Total reclassification adjustments		(1,702	)		—
Total change		13,204			—
Balance at December 31, 2009	$	85,194		$	—

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Gulf Power Company 2009 Annual Report

Components of net periodic pension cost were as follows:

	2009			2008			2007
	(in thousands)
Service cost	$	6,478		$	6,750		$	6,835
Interest cost		17,139			15,475			14,519
Expected return on plan assets		(24,357	)		(23,757	)		(21,934	)
Recognized net (gain) loss		224			334			342
Net amortization		1,478			1,478			1,419
Net periodic pension cost	$	962		$	280		$	1,181

Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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, 2009, estimated benefit payments were as follows:

	Benefit Payments
	(in thousands)
2010	$	14,388
2011		15,105
2012		15,825
2013		16,696
2014		18,102
2015 to 2019		106,458

Other Postretirement Benefits

Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

	2009			2008
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	72,391		$	73,909
Service cost		1,328			1,766
Interest cost		4,705			5,671
Benefits paid		(4,115	)		(4,864	)
Actuarial (gain) loss		497			(4,522	)
Plan amendments		(2,416	)		—
Retiree drug subsidy		250			431
Balance at end of year		72,640			72,391
Change in plan assets
Fair value of plan assets at beginning of year		13,180			19,610
Actual return (loss) on plan assets		2,735			(5,556	)
Employer contributions		2,923			3,559
Benefits paid		(3,865	)		(4,433	)
Fair value of plan assets at end of year		14,973			13,180
Accrued liability	$	(57,667	)	$	(59,211	)

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Gulf Power Company 2009 Annual Report

Other postretirement benefit 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. 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. The actual composition of the Company’s other postretirement benefit plan assets as of the end of the year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		28	%		32	%		33	%
International equity		27			28			22
Fixed income		18			18			17
Special situations		3			—			—
Real estate investments		14			12			19
Private equity		10			10			9
Total		100	%		100	%		100	%

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is comprised of domestic bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Trust-owned life insurance.Some of the Company’s taxable trusts invest in these investments in order to minimize the impact of taxes on the portfolio.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

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The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable
	Assets			Inputs			Inputs
As of December 31, 2009:	(Level 1)			(Level 2)			(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	2,706		$	1,119		$	—	$	3,825
International equity*		3,499			348			—		3,847
Fixed income:
U.S. Treasury, government, and agency bonds		—			1,008			—		1,008
Mortgage- and asset-backed securities		—			274			—		274
Corporate bonds		—			675			—		675
Pooled funds		—			553			—		553
Cash equivalents and other		8			827			—		835
Trust-owned life insurance		—			—			—		—
Special situations		—			—			—		—
Real estate investments		420			—			1,326		1,746
Private equity		—			—			1,346		1,346
Total	$	6,633		$	4,804		$	2,672	$	14,109
Liabilities:
Derivatives		(11	)		(3	)		—		(14	)
Total	$	6,622		$	4,801		$	2,672	$	14,095

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	2,591		$	1,055	$	—	$	3,646
International equity*		2,332			216		—		2,548
Fixed income:
U.S. Treasury, government, and agency bonds		—			1,089		—		1,089
Mortgage- and asset-backed securities		—			516		—		516
Corporate bonds		—			706		—		706
Pooled funds		—			551		—		551
Cash equivalents and other		54			499		—		553
Trust-owned life insurance		—			—		—		—
Special situations		—			—		—		—
Real estate investments		355			—		2,073		2,428
Private equity		—			—		1,211		1,211
Total	$	5,332		$	4,632	$	3,284	$	13,248
Liabilities:
Derivatives		(20	)		—		—		(20	)
Total	$	5,312		$	4,632	$	3,284	$	13,228

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Gulf Power Company 2009 Annual Report

Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate			Private		Real Estate			Private
	Investments			Equity		Investments			Equity
	(in thousands)					(in thousands)
Beginning balance	$	2,073		$	1,211	$	2,499		$	1,243
Actual return on investments:
Related to investments held at year end		(624	)		68		(339	)		(297	)
Related to investments sold during the year		(154	)		25		9			59
Total return on investments		(778	)		93		(330	)		(238	)
Purchases, sales, and settlements		31			42		(96	)		206
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	1,326		$	1,346	$	2,073		$	1,211

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable in an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued utilizing matrix pricing, a common model utilizing observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of:

	2009			2008
	(in thousands)
Other regulatory assets, deferred	$	5,861		$	9,922
Other current liabilities		—			(500	)
Employee benefit obligations		(57,667	)		(58,711	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2010.

	Prior Service		Net			Transition
	Cost		(Gain)Loss			Obligation
	(in thousands)
Balance at December 31, 2009:
Regulatory asset	$	881	$	4,273		$	707
Balance at December 31, 2008:
Regulatory asset	$	3,187	$	5,302		$	1,433
Estimated amortization as net periodic postretirement cost in 2010:
Regulatory asset	$	186	$	(37	)	$	257

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The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory
	Assets
	(in thousands)
Balance at December 31, 2007	$	8,040
Net loss		2,759
Change in prior service costs/transition obligation		—
Reclassification adjustments:
Amortization of transition obligation		(445	)
Amortization of prior service costs		(432	)
Amortization of net gain		—
Total reclassification adjustments		(877	)
Total change		1,882
Balance at December 31, 2008	$	9,922
Net gain		(1,097	)
Change in prior service costs/transition obligation		(2,416	)
Reclassification adjustments:
Amortization of transition obligation		(323	)
Amortization of prior service costs		(293	)
Amortization of net gain		68
Total reclassification adjustments		(548	)
Total change		(4,061	)
Balance at December 31, 2009	$	5,861

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

	2009			2008			2007
				(in thousands)
Service cost	$	1,328		$	1,413		$	1,351
Interest cost		4,705			4,536			4,330
Expected return on plan assets		(1,436	)		(1,452	)		(1,320	)
Net amortization		548			702			792
Net postretirement cost	$	5,145		$	5,199		$	5,153

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2009, 2008, and 2007 by approximately $1.3 million, $1.4 million, and $1.5 million, respectively.

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Gulf Power Company 2009 Annual Report

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO 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)
2010	$	4,528	$	(382	)	$	4,146
2011		4,942		(422	)		4,520
2012		5,173		(482	)		4,691
2013		5,385		(543	)		4,842
2014		5,606		(607	)		4,999
2015 to 2019		29,912		(4,076	)		25,836

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual salary increase of 3.50%.

	2009			2008			2007
Discount rate:
Pension plans		5.93	%		6.75	%		6.30	%
Other postretirement benefit plans		5.84			6.75			6.30
Annual salary increase		4.18			3.75			3.75
Long-term return on plan assets
Pension plans		8.50			8.50			8.50
Other postretirement benefit plans		8.36			8.38			8.36

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2009 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in thousands)
Benefit obligation	$	3,571	$	3,214
Service and interest costs		273		294

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $3.7 million, $3.5 million, and $3.5 million, respectively.

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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 such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company’s Plant Crist. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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

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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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company 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.

The Company’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $65.2 million as of December 31, 2009. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company’s 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 through the Company’s environmental cost recovery clause; therefore, there is no impact to net income as a result of these liabilities.

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, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company’s financial statements.

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FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that the Company possesses or has exercised any market power. The agreement likewise does not require the Company to make any refunds related to sales during the 15-month refund period. Under the agreement, the Company will donate $0.1 million to nonprofit organizations in the State of Florida for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

Retail Regulatory Matters

General

The Company’s rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company’s rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation, and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company’s base rates.

On November 2, 2009, the Florida PSC approved the Company’s annual rate requests for its purchased power capacity, energy conservation, and environmental compliance cost recovery factors for 2010. On December 1, 2009, the Florida PSC approved the Company’s annual rate request for its 2010 fuel cost recovery factor, which includes both fuel and purchased energy costs. The net effect of the approved changes to the Company’s cost recovery factors for 2010 is a 3.9% rate increase for residential customers using 1,000 kilowatt-hours per month. The billing factors for 2010 are intended to allow the Company to recover projected 2010 costs as well as refund or collect the 2009 over or under recovered amounts in 2010. Cost recovery revenues, as recorded on the financial

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statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factors has no significant effect on the Company’s revenues or net income, but does impact annual cash flow.

Fuel Cost Recovery

The Company petitions for fuel cost recovery rates to be approved by the Florida PSC on an annual basis. The fuel cost recovery rates include the costs of fuel and purchased energy. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. If the projected fuel cost over or under recovery exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery is being requested. As of December 31, 2009 and 2008, the Company had an under recovered fuel balance of approximately $2.4 million and $96.7 million, respectively, which is included in current assets in the balance sheets.

Purchased Power Capacity Recovery

The Florida PSC allows the Company to recover its costs for capacity purchased from other power producers under PPAs through a separate cost recovery component or factor in the Company’s retail energy rates. Like the other specific cost recovery factors included in the Company’s retail energy rates, the rates for purchased capacity are set annually on a calendar year basis. When the Company enters into a new PPA, it is reviewed and approved by the Florida PSC for cost recovery purposes. As of December 31, 2009 and 2008, the Company had an over recovered purchased power capacity balance of approximately $1.5 million and $0.3 million, respectively, which is included in other regulatory liabilities, current in the balance sheets.

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. In August 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company’s plan for complying with certain federal and state regulations addressing air quality. The Company’s environmental compliance plan as filed in March 2007 contemplates implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the current plan that are scheduled to be implemented in the 2007 through 2011 timeframe. On April 1, 2009, the Company filed an update to the plan which was approved by the Florida PSC on November 2, 2009. The Florida PSC acknowledged that the costs associated with the Company’s Clean Air Interstate Rule and Clean Air Visibility Rule compliance plan are eligible for recovery through the environmental cost recovery clause. At December 31, 2009 and 2008, the over recovered environmental balance was approximately $11.7 million and $71 thousand, respectively, which is included in other regulatory liabilities, current in the balance sheets.

4. JOINT OWNERSHIP AGREEMENTS

The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company’s agent with respect to the construction, operation, and maintenance of these units.

The Company and Georgia Power jointly own the 818 MWs 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 and the Company is responsible for providing its own financing.

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At December 31, 2009, the Company’s percentage ownership and its investment in these jointly owned facilities were as follows:

	Plant Scherer			Plant Daniel
	Unit 3 (coal)			Units 1 & 2 (coal)
	(in thousands)
Plant in service	$	242,078	(a)	$	262,315
Accumulated depreciation		100,242			150,190
Construction work in progress		70,657			1,542
Ownership		25	%		50	%

(a) Includes net plant acquisition adjustment of $3.1 million.

5. INCOME TAXES

Southern Company files 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 it filed a separate income tax return. In accordance with Internal Revenue Service (IRS) regulations, each company is jointly and severally liable for the tax liability.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2009			2008		2007
	(in thousands)
Federal -
Current	$	62,980		$	26,592	$	51,321
Deferred		(14,453	)		21,481		(9,431	)
		48,527			48,073		41,890
State -
Current		6,590			3,563		6,581
Deferred		(2,092	)		2,467		(1,388	)
		4,498			6,030		5,193
Total	$	53,025		$	54,103	$	47,083

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The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

	2009		2008
	(in thousands)
Deferred tax liabilities-
Accelerated depreciation	$	332,971	$	284,653
Fuel recovery clause		965		39,176
Pension and other employee benefits		15,539		15,356
Regulatory assets associated with employee benefit obligations		37,768		34,787
Regulatory assets associated with asset retirement obligations		5,106		4,877
Other		9,084		3,747
Total		401,433		382,596
Deferred tax assets-
Federal effect of state deferred taxes		13,076		14,039
Postretirement benefits		18,465		17,428
Pension and other employee benefits		41,124		38,156
Property reserve		10,642		4,872
Other comprehensive loss		1,546		3,097
Asset retirement obligations		5,106		4,877
Other		16,995		7,003
Total		106,954		89,472
Net deferred tax liabilities		294,479		293,124
Less current portion, net		2,926		(38,770	)
Accumulated deferred income taxes in the balance sheets	$	297,405	$	254,354

At December 31, 2009, the tax-related regulatory assets to be recovered from customers was $39.0 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, 2009, the tax-related regulatory liabilities to be credited to customers was $11.4 million. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

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 $1.6 million in 2009, $1.7 million in 2008, and $1.7 million in 2007. At December 31, 2009, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		1.7			2.5			2.5
Non-deductible book depreciation		0.3			0.0			0.4
Difference in prior years’ deferred and current tax rate		(0.4	)		(0.5	)		(0.6	)
Production activities deduction		(0.9	)		0.1			(1.4	)
Allowance for funds used during construction		(4.9	)		(2.2	)		(0.6	)
Other, net		0.3			(0.8	)		(0.4	)
Effective income tax rate		31.1	%		34.1	%		34.9	%

The decrease in the 2009 effective tax rate is primarily the result of an increase in nontaxable allowance for equity funds used during construction.

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The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, the Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits increased by $1.3 million, resulting in a balance of $1.6 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009		2008			2007
	(thousands)
Unrecognized tax benefits at beginning of year	$	294	$	887		$	211
Tax positions from current periods		455		93			469
Tax positions from prior periods		890		11			207
Reductions due to settlements		—		(697	)		—
Reductions due to expired statute of limitations		—		—			—
Balance at end of year	$	1,639	$	294		$	887

The tax positions from current periods increase for 2009 relate primarily to the production activities deduction tax position and other miscellaneous uncertain tax positions. The tax positions increase from prior periods for 2009 relates primarily to the production activities deduction tax position. See “Effective Tax Rate” above for additional information.

Impact on the Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
	(thousands)
Tax positions impacting the effective tax rate	$	1,639	$	294	$	887
Tax positions not impacting the effective tax rate		—		—		—
Balance of unrecognized tax benefits	$	1,639	$	294	$	887

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008			2007
	(thousands)
Interest accrued at beginning of year	$	17	$	58		$	5
Interest reclassified due to settlements		—		(54	)		—
Interest accrued during the year		73		13			53
Balance at end of year	$	90	$	17		$	58

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized benefit with respect to the majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

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6. FINANCING

Securities Due Within One Year

At December 31, 2009, the Company had $140 million of senior notes due to mature within one year. The date of maturity for these notes is June 2010.

Bank Term Loans

At December 31, 2009, the Company had a $110 million bank loan outstanding, which matures in April 2011.

Senior Notes

At December 31, 2009 and 2008, the Company had a total of $727.5 million and $588.7 million of senior notes outstanding, respectively. These senior notes are effectively subordinate to all secured debt of the Company which totaled approximately $41 million at December 31, 2009.

Pollution Control Revenue 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 has $288.0 million of outstanding pollution control revenue bonds and is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

Outstanding Classes of Capital Stock

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company’s preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company’s preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2009. The Company’s preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, one series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.

In January 2009, the Company issued to Southern Company 1,350,000 shares of the Company’s common stock, without par value, and realized proceeds of $135 million. On January 25, 2010, the Company issued to Southern Company 500,000 shares of the Company’s common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company’s short-term debt and for other general corporate purposes, including the Company’s continuous construction program.

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Assets Subject to Lien

The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an outstanding principal amount of $41 million.

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 December 31, 2009, the Company had $220 million of lines of credit with banks, all of which remained unused. These bank credit arrangements will expire in 2010 and $70 million contain provisions allowing one-year term loans executable at expiration. Of the $220 million, $69 million provides support for variable rate pollution control bonds, and $151 million provides liquidity support for

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the Company’s commercial paper program and other general corporate purposes, including the Company’s continuous construction program. Commitment fees average less than³/4 of 1% for the Company.

Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65%, as defined in the arrangements. At December 31, 2009, 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.

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. At December 31, 2009, the Company had $88.9 million of commercial paper outstanding. At December 31, 2008, the Company had $89.9 million of commercial paper and $50 million of short-term bank notes outstanding. During 2009, the peak amount outstanding for short-term debt was $152.1 million and the average amount outstanding was $51.7 million. The peak amount outstanding for short-term debt in 2008 was $141.2 million and the average amount outstanding was $36.9 million. The average annual interest rate on short-term debt was 1.0% and 2.2% for 2009 and 2008, respectively.

7. COMMITMENTS

Construction Program

The Company is engaged in a continuous construction program, the cost of which is currently estimated to total $271.4 million in 2010, $350.2 million in 2011, and $418.5 million in 2012. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2009, significant purchase commitments were outstanding in connection with the ongoing construction program.

Included in the amounts above are $113.4 million in 2010, $194.8 million in 2011, and $194.2 million in 2012 for environmental expenditures. The Company does not have any significant 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 a combined cycle generating facility. The LTSA provides that GE will perform all planned inspections on the covered equipment, which generally 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 limits and scope specified in the LTSA.

In general, the LTSA is in effect through two major inspection cycles of the unit. Scheduled payments to GE, which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Total remaining payments to GE under the LTSA for facilities owned are currently estimated at $59.2 million over the remaining life of the LTSA, which is currently estimated to be up to 8 years. However, the LTSA contains various cancellation provisions at the option of the Company.

Payments made under the LTSA 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 for 2009 and 2008, respectively. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

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Gulf Power Company 2009 Annual Report

Limestone Commitments

As part of the Company’s program to reduce sulfur dioxide emissions from certain of its coal plants, the Company has entered into various long-term commitments for the procurement of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur content. The Company has a minimum contractual obligation of 0.8 million tons equating to approximately $67.7 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are $6.0 million in 2010, $6.2 million in 2011, $6.3 million in 2012, $6.5 million in 2013, and $6.7 million in 2014. Limestone costs are recovered through the environmental cost recovery clause.

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, the Company has entered into various long-term commitments for the procurement of fossil fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emissions 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, 2009. Also, the Company has entered into various long-term commitments for the purchase of capacity, electricity, and transmission. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause.

Total estimated minimum long-term obligations at December 31, 2009 were as follows:

		Commitments
		Purchased Power*		Natural Gas		Coal
	��	(in thousands)
2010		$	39,432	$	112,080	$	515,241
2011			41,185		79,724		75,561
2012			41,289		57,842		—
2013			41,380		47,664		—
2014			55,937		53,512		—
2015 and thereafter			659,261		130,889		—
Total		$	878,484	$	481,711	$	590,802

* Included above is $69.9 million in obligations with affiliated companies. Certain PPAs are accounted for as operating leases.

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 traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power 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 $10.1 million, $5.0 million, and $4.7 million for 2009, 2008, and 2007, respectively. Included in these lease expenses are rail car lease costs which 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 $7.9 million in 2009, $4.0 million in 2008, and $4.4 million in 2007. 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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Gulf Power Company 2009 Annual Report

At December 31, 2009, estimated minimum rental commitments for noncancelable operating leases were as follows:

	Minimum Lease Payments
	Barges &
	Rail Cars		Other		Total
	(in thousands)
2010	$	12,380	$	2,145	$	14,525
2011		9,768		2,053		11,821
2012		8,266		452		8,718
2013		6,925		233		7,158
2014		5,504		131		5,635
2015 and thereafter		1,613		—		1,613
Total	$	44,456	$	5,014	$	49,470

The Company and Mississippi Power jointly entered into operating lease agreements for aluminum rail cars for the transportation of coal to Plant Daniel. The Company has the option to purchase the rail cars 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 rail cars that do not include purchase options.

The Company entered into operating lease agreements for barges and tow boats for the transport of coal at Plant Crist. The Company has the option to renew the leases at the end of each lease term. No barge lease costs were incurred for 2009, 2008, or 2007.

In addition to rail car leases, the Company has other operating leases for fuel handling equipment at Plant Daniel. The Company’s share of these leases was charged to fuel handling expense in the amount of $0.3 million in 2009. The Company’s annual lease payments for 2010 to 2014 will average approximately $0.2 million.

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, 2009, there were 308 current and former employees of the Company participating in the stock option plan, and there were 21 million shares of Southern Company common stock remaining available for awards under this plan. 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. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. 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. For certain stock option awards a change in control will provide accelerated vesting.

The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:

Year Ended December 31	2009			2008			2007
Expected volatility		15.6	%		13.1	%		14.8	%
Expected term(in years)		5.0			5.0			5.0
Interest rate		1.9	%		2.8	%		4.6	%
Dividend yield		5.4	%		4.5	%		4.3	%
Weighted average grant-date fair value	$	1.80		$	2.37		$	4.12

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Gulf Power Company 2009 Annual Report

The Company’s activity in the stock option plan for 2009 is summarized below:

	Shares Subject			Weighted Average
	to Option			Exercise Price
Outstanding at December 31, 2008		1,279,765		$	32.25
Granted		435,820			31.38
Exercised		(56,735	)		24.68
Cancelled		(729	)		35.30
Outstanding at December 31, 2009		1,658,121		$	32.28
Exercisable at December 31, 2009		994,073		$	31.81

The number of stock options vested, and expected to vest in the future, as of December 31, 2009 was not significantly different from the number of stock options outstanding at December 31, 2009 as stated above. As of December 31, 2009, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.4 years and 4.9 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $3.2 million and $2.4 million, respectively.

As of December 31, 2009, there was $0.2 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.

For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option awards recognized in income was $0.9 million, $0.8 million, and $1.1 million, respectively, with the related tax benefit also recognized in income of $0.4 million, $0.3 million, and $0.4 million, respectively.

The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $0.2 million, $1.3 million, and $3.0 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises for the years ended December 31, 2009, 2008, and 2007 totaled $0.1 million, $0.5 million, and $1.1 million, respectively.

9. FAIR VALUE MEASUREMENTS

The fair value measurement is based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
At December 31, 2009:	(Level 1)			(Level 2)		(Level 3)		Total
			(in thousands)
Assets:
Energy-related derivatives	$	—		$	202	$	—	$	202
Interest rate derivatives		—			2,934		—		2,934
Cash equivalents and restricted cash		9,366			—		—		9,366
Total	$	9,366		$	3,136	$	—	$	12,502
Liabilities:
Energy-related derivatives	$	—		$	13,889	$	—	$	13,889

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note 10 for additional information. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. These financial instruments and investments are valued primarily using the market approach.

As of December 31, 2009, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

			Unfunded	Redemption	Redemption
As of December 31, 2009:	Fair Value		Commitments	Frequency	Notice Period
	(in thousands)
Cash equivalents and restricted cash:
Money market funds	$	9,366	None	Daily	Not applicable

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company investment in the money market funds.

As of December 31, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
		(in thousands)
Long-term debt:
2009	$	1,118,914	$	1,137,761
2008	$	849,265	$	831,763

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

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Gulf Power Company 2009 Annual Report

10. DERIVATIVES

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 its exposures, where possible, 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. The Company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

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 manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of two methods:

• Regulatory Hedges- Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause.

• Not Designated- Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At December 31, 2009, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Net Purchased	Longest Hedge	Longest Non-Hedge
mmBtu*	Date	Date
(in thousands)
11,000	2014	—

* mmBtu — million British thermal units

Interest Rate Derivatives

The Company also enters into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

At December 31, 2009, the Company had outstanding interest rate derivatives designated as cash flow hedges on forecasted debt as follows:

		Weighted				Fair Value
		Average				Gain (Loss)
Notional	Variable Rate	Fixed Rate			Hedge Maturity	December 31,
Amount	Received	Paid			Date	2009
(in thousands)						(in thousands)
$100,000	3-month LIBOR		3.79	%	April 2020	$	2,934

The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2010 are $0.9 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2018.

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

	Asset Derivatives						Liability Derivatives
		Balance Sheet					Balance Sheet
Derivative Category		Location	2009		2008		Location	2009		2008
			(in thousands)					(in thousands)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:		Other current assets	$	142	$	1,017	Liabilities from risk    management activities	$	9,442	$	26,928
		Other deferred charges and assets		48		54	Other deferred    credits and liabilities		4,447		5,305
Total derivatives designated as hedging instruments for regulatory purposes			$	190	$	1,071		$	13,889	$	32,233
Derivatives designated as hedging instruments in cash flow hedges
Interest rate derivatives:		Other current assets	$	2,934	$	—	Liabilities from risk    management activities	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:		Other current assets	$	12	$	—	Liabilities from risk    management activities	$	—	$	—
Total			$	3,136	$	1,071		$	13,889	$	32,233

All derivative instruments are measured at fair value. See Note 9 for additional information.

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Gulf Power Company 2009 Annual Report

At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

	Unrealized Losses							Unrealized Gains
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in thousands)							(in thousands)
Energy-related derivatives:	Other regulatory   assets, current	$	(9,442	)	$	(26,928	)	Other regulatory    liabilities, current	$	142	$	1,017
	Other regulatory    assets, deferred		(4,447	)		(5,305	)	Other regulatory    liabilities, deferred		48		54
Total energy-related derivative gains (losses)		$	(13,889	)	$	(32,233	)		$	190	$	1,071

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in							Gain (Loss) Reclassified from Accumulated
Derivatives in Cash Flow	OCI on Derivative							OCI into Income (Effective Portion)
Hedging Relationships	(Effective Portion)								Amount
								Statements of
Derivative Category	2009		2008			2007		Income Location	2009			2008			2007
	(in thousands)								(in thousands)
Interest rate derivatives	$	2,934	$	(2,792	)	$	602	Interest expense	$	(1,085	)	$	(949	)	$	(696	)

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial.

Contingent Features

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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2009, the fair value of derivative liabilities with contingent features was $3.1 million.

At December 31, 2009, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33.3 million.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to debt and preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participated in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

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NOTES (continued)
Gulf Power Company 2009 Annual Report

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2009 and 2008 are as follows:

					Net Income After
	Operating		Operating		Dividends on
Quarter Ended	Revenues		Income		Preference Stock
	(in thousands)
March 2009	$	284,284	$	30,914	$	16,542
June 2009		341,095		54,320		32,269
September 2009		377,641		67,392		41,208
December 2009		299,209		36,036		21,214
March 2008	$	311,535	$	40,708	$	19,530
June 2008		349,867		52,314		26,992
September 2008		421,841		69,039		37,343
December 2008		303,960		30,628		14,480

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

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SELECTED FINANCIAL AND OPERATING DATA 2005-2009
Gulf Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands)	$	1,302,229	$	1,387,203	$	1,259,808	$	1,203,914	$	1,083,622
Net Income after Dividends on Preference Stock (in thousands)	$	111,233	$	98,345	$	84,118	$	75,989	$	75,209
Cash Dividends on Common Stock (in thousands)	$	89,300	$	81,700	$	74,100	$	70,300	$	68,400
Return on Average Common Equity (percent)		12.18		12.66		12.32		12.29		12.59
Total Assets (in thousands)	$	3,293,607	$	2,879,025	$	2,498,987	$	2,340,489	$	2,175,797
Gross Property Additions (in thousands)	$	450,421	$	390,744	$	239,337	$	147,086	$	142,583
Capitalization (in thousands):
Common stock equity	$	1,004,292	$	822,092	$	731,255	$	634,023	$	602,344
Preference stock		97,998		97,998		97,998		53,887		53,891
Long-term debt		978,914		849,265		740,050		696,098		616,554
Total (excluding amounts due within one year)	$	2,081,204	$	1,769,355	$	1,569,303	$	1,384,008	$	1,272,789
Capitalization Ratios (percent):
Common stock equity		48.3		46.5		46.6		45.8		47.3
Preference stock		4.7		5.5		6.2		3.9		4.2
Long-term debt		47.0		48.0		47.2		50.3		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
Standard and Poor’s		—		—		—		—		A+
Fitch		—		—		—		—		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		374,091		373,595		373,036		364,647		354,466
Commercial		53,272		53,548		53,838		53,466		53,398
Industrial		279		287		298		295		298
Other		512		499		491		484		479
Total		428,154		427,929		427,663		418,892		408,641
Employees (year-end)		1,365		1,342		1,324		1,321		1,335

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SELECTED FINANCIAL AND OPERATING DATA 2005-2009 (continued)
Gulf Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands):
Residential	$	588,073	$	581,723	$	537,668	$	510,995	$	465,346
Commercial		376,125		369,625		329,651		305,049		273,114
Industrial		138,164		165,564		135,179		132,339		123,044
Other		4,206		3,854		3,831		3,655		3,355
Total retail		1,106,568		1,120,766		1,006,329		952,038		864,859
Wholesale — non-affiliates		94,105		97,065		83,514		87,142		84,346
Wholesale — affiliates		32,095		106,989		113,178		118,097		91,352
Total revenues from sales of electricity		1,232,768		1,324,820		1,203,021		1,157,277		1,040,557
Other revenues		69,461		62,383		56,787		46,637		43,065
Total	$	1,302,229	$	1,387,203	$	1,259,808	$	1,203,914	$	1,083,622
Kilowatt-Hour Sales (in thousands):
Residential		5,254,491		5,348,642		5,477,111		5,425,491		5,319,630
Commercial		3,896,105		3,960,923		3,970,892		3,843,064		3,735,776
Industrial		1,727,106		2,210,597		2,048,389		2,136,439		2,160,760
Other		25,121		23,237		24,496		23,886		22,730
Total retail		10,902,823		11,543,399		11,520,888		11,428,880		11,238,896
Wholesale — non-affiliates		1,813,592		1,816,839		2,227,026		2,079,165		2,295,850
Wholesale — affiliates		870,470		1,871,158		2,884,440		2,937,735		1,976,368
Total		13,586,885		15,231,396		16,632,354		16,445,780		15,511,114
Average Revenue Per Kilowatt-Hour (cents):
Residential		11.19		10.88		9.82		9.42		8.75
Commercial		9.65		9.33		8.30		7.94		7.31
Industrial		8.00		7.49		6.60		6.19		5.69
Total retail		10.15		9.71		8.73		8.33		7.70
Wholesale		4.70		5.53		3.85		4.09		4.11
Total sales		9.07		8.70		7.23		7.04		6.71
Residential Average Annual Kilowatt-Hour Use Per Customer		14,049		14,274		14,755		15,032		15,181
Residential Average Annual Revenue Per Customer	$	1,572	$	1,552	$	1,448	$	1,416	$	1,328
Plant Nameplate Capacity Ratings (year-end) (megawatts)		2,659		2,659		2,659		2,659		2,712
Maximum Peak-Hour Demand (megawatts):
Winter		2,310		2,360		2,215		2,195		2,124
Summer		2,538		2,533		2,626		2,479		2,433
Annual Load Factor (percent)		53.8		56.7		55.0		57.9		57.7
Plant Availability Fossil-Steam (percent)		89.7		88.6		93.4		91.3		89.7
Source of Energy Supply (percent):
Coal		61.7		77.3		81.8		82.5		79.7
Gas		28.0		15.3		13.6		12.4		13.1
Purchased power -
From non-affiliates		2.2		2.6		1.6		1.9		2.8
From affiliates		8.1		4.8		3.0		3.2		4.4
Total		100.0		100.0		100.0		100.0		100.0

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MISSISSIPPI POWER COMPANY

FINANCIAL SECTION

II-310

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Mississippi Power Company 2009 Annual Report

The management of Mississippi Power Company (the “Company”) 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 the 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. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

/s/ Anthony J. Topazi

Anthony J. Topazi
President and Chief Executive Officer

/s/ Frances Turnage

Frances Turnage
Vice President, Treasurer, and Chief Financial Officer

February 25, 2010

II-311

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, 2009 and 2008, 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, 2009. 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 financial statements (pages II-339 to II-380) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

II-312

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power Company 2009 Annual Report

OVERVIEW

Business Activities

Mississippi Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of rising costs. The Company has various regulatory mechanisms that operate to address cost recovery.

Appropriately balancing required costs and capital expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future. Hurricane Katrina, the worst natural disaster in the Company’s history, hit the Gulf Coast of Mississippi in August 2005, causing substantial damage to the Company’s service territory. All of the Company’s 195,000 customers were without service immediately after the storm. Through a coordinated effort with Southern Company, as well as non-affiliated companies, the Company restored power to all who could receive it within 12 days. However, due to obstacles in the rebuilding process coupled with the recessionary economy, as of December 31, 2009, the Company had over 8,800 fewer retail customers as compared to pre-storm levels. See Note 1 to the financial statements under “Government Grants” and Note 3 to the financial statements under “Retail Regulatory Matters — Storm Damage Cost Recovery” for additional information.

The Company’s retail base rates are set under the Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi Public Service Commission (PSC). PEP was designed with the objective to 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.

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 are used to measure the Company’s performance for customers and employees.

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%); service reliability, measured in outage minutes per customer (40%); and customer satisfaction, measured in a survey of residential customers (20%). 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 after dividends on preferred stock. 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. The actual EFOR performance for 2009 was the best in the history of the Company. Net income after dividends on preferred stock is the primary measure of the Company’s financial performance. Recognizing the critical role in the Company’s success played by the Company’s employees, employee-related measures are a significant management focus. These measures include safety and inclusion. The 2009 safety performance of the Company was the third best in the history of the Company with an Occupational Safety and Health Administration Incidence Rate of 0.62. This achievement resulted in the Company being recognized as one of the top in safety performance among all utilities in the Southeastern Electric Exchange. Inclusion initiatives resulted in performance at target levels for the year.

II-313

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

The Company’s 2009 results compared with its targets for some of these key indicators are reflected in the following chart.

	2009	2009
	Target	Actual
Key Performance Indicator	Performance	Performance
Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season EFOR	3.0% or less	0.76%
Net income after dividends on preferred stock	$83.5 million	$85.0 million

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The performance achieved in 2009 reflects the continued emphasis that management places on all of these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations.

Earnings

The Company’s net income after dividends on preferred stock was $85.0 million in 2009 compared to $86.0 million in 2008. The 1.2% decrease in 2009 was primarily the result of decreases in wholesale energy revenues and total other income and (expense) primarily resulting from an increase in interest expense and decreases in contracting work performed for customers, as well as an increase in income tax expense. These decreases in earnings were partially offset by an increase in territorial base revenues primarily due to a wholesale base rate increase effective January 2009 and higher demand as well as a decrease in other non-fuel related expenses. See Note 3 to the financial statements under “FERC Matters” for additional information.

Net income after dividends on preferred stock was $86.0 million in 2008 compared to $84.0 million in 2007. The 2.4% increase in 2008 was primarily the result of an increase in territorial base revenues due to a retail base rate increase effective January 2008 and an increase in wholesale capacity revenues, partially offset by an increase in depreciation and amortization primarily due to the amortization of regulatory items, an increase in non-fuel related expenses, and an increase in charitable contributions. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

Net income after dividends on preferred stock was $84.0 million in 2007 compared to $82.0 million in 2006. The 2.4% increase in 2007 was primarily the result of an increase in territorial base revenues due to a retail base rate increase effective April 1, 2006, territorial sales growth, and an increase in total other income and (expense) as a result of charitable contributions in 2006. These factors were partially offset by an increase in non-fuel related expenses and an increase in depreciation and amortization expenses.

RESULTS OF OPERATIONS

A condensed statement of income follows:

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008			2007
	(in millions)
Operating revenues	$	1,149.4		$	(107.1	)	$	142.8		$	104.5
Fuel		519.7			(66.8	)		92.2			55.6
Purchased power		91.9			(34.6	)		30.7			22.6
Other operations and maintenance		246.8			(13.3	)		4.8			18.6
Depreciation and amortization		70.9			(0.1	)		10.7			13.5
Taxes other than income taxes		64.1			(1.0	)		4.8			(0.6	)
Total operating expenses		993.4			(115.8	)		143.2			109.7
Operating income		156.0			8.7			(0.4	)		(5.2	)
Total other income and (expense)		(19.1	)		(7.8	)		(1.1	)		10.9
Income taxes		50.2			1.9			(3.4	)		3.7
Net income		86.7			(1.0	)		1.9			2.0
Dividends on preferred stock		1.7			—			—			—
Net income after dividends on preferred stock	$	85.0		$	(1.0	)	$	1.9		$	2.0

II-314

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Operating Revenues

Details of the Company’s operating revenues in 2009 and the prior two years were as follows:

	Amount
	2009			2008			2007
	(in millions)
Retail — prior year	$	785.4		$	727.2		$	647.2
Estimated change in —
Rates and pricing		0.6			18.8			8.7
Sales growth (decline)		(1.3	)		(1.1	)		12.3
Weather		1.7			(1.8	)		(2.5	)
Fuel and other cost recovery		4.5			42.3			61.5
Retail — current year		790.9			785.4			727.2
Wholesale revenues —
Non-affiliates		299.3			353.8			323.1
Affiliates		44.5			100.9			46.2
Total wholesale revenues		343.8			454.7			369.3
Other operating revenues		14.7			16.4			17.2
Total operating revenues	$	1,149.4		$	1,256.5		$	1,113.7
Percent change		(8.5	)%		12.8	%		10.4	%

Total retail revenues for 2009 increased 0.7% when compared to 2008 primarily as a result of slightly higher energy sales and fuel revenues. Total retail revenues for 2008 increased 8.0% when compared to 2007 primarily as a result of a retail base rate increase effective in January 2008 and higher fuel revenues. Total retail revenues for 2007 increased 12.4% when compared to 2006 primarily as a result of an increase in territorial sales growth, a retail base rate increase effective in April 2006, and the Environmental Compliance Overview (ECO) Plan rate increase effective in May 2007. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (or decline) and weather.

Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power, and do not affect net income. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information. The fuel and other cost recovery revenues increased in 2009 when compared to 2008 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside the Company’s service territory. The fuel and other cost recovery revenues increased in 2008 when compared to 2007 primarily as a result of the increase in fuel and purchased power expenses. The fuel and other cost recovery revenues increased in 2007 when compared to 2006 as a result of higher fuel costs.

Wholesale revenues from sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from sales to non-affiliates decreased $54.5 million, or 15.4%, in 2009 as compared to 2008 as a result of a $54.1 million decrease in energy revenues, of which $27.6 million was associated with lower fuel prices and $26.4 million was associated with a decrease in kilowatt-hour (KWH) sales, and a $0.5 million decrease in capacity revenues. Wholesale revenues from sales to non-affiliates increased $30.7 million, or 9.5%, in 2008 as compared to 2007 as a result of a $30.4 million increase in energy revenues, of which $40.4 million was associated with higher fuel prices and a $0.3 million increase in capacity revenues, partially offset by a $10.0 million decrease in KWH sales. Wholesale revenues from sales to non-affiliates increased $54.3 million, or 20.2%, in 2007 as compared to 2006 as a result of a $51.5 million increase in energy revenues, of which $32.0 million was associated with increased KWH sales and $19.5 million was associated with higher fuel prices, and a $2.8 million increase in capacity revenues.

II-315

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Included in wholesale revenues from sales to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. The related revenues increased 1.5%, 8.3%, and 12.6%, in 2009, 2008, and 2007, respectively. The 2009 increase was driven by higher demand which was the result of some brief periods of weather extremes and a base rate increase effective in January 2009. 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 (MBRs) that generally provide a margin above the Company’s variable cost to produce the energy.

Wholesale revenues from sales to affiliated companies within the Southern Company system will vary from year to year depending on demand, 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). Wholesale revenues from sales to affiliated companies decreased 55.9% in 2009 when compared to 2008, increased 118.6% in 2008 when compared to 2007, and decreased 39.5% in 2007 when compared to 2006. These energy sales do not have a significant impact on earnings since the energy is generally sold at marginal cost.

Other operating revenues in 2009 decreased $1.7 million, or 10.6%, from 2008 primarily due to a $1.0 million decrease in transmission revenues. Other operating revenues in 2008 decreased $0.9 million, or 5.0%, from 2007 primarily due to a sale of oil inventory and a customer contract buyout in 2007 totaling $0.9 million. Other operating revenues in 2007 increased $0.5 million, or 2.9%, from 2006 primarily due to a $1.0 million increase in miscellaneous revenues from a sale of oil inventory during the year, partially offset by a $0.6 million decrease in rent from electric property.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2009 and percent change by year were as follows:

	KWHs		Percent Change
	2009		2009			2008			2007
	(in millions)
Residential		2,092		(1.4	)%		(0.6	)%		0.8	%
Commercial		2,851		(0.2	)		(0.7	)		7.5
Industrial		4,330		3.4			(3.0	)		4.2
Other		39		0.0			0.3			4.9
Total retail		9,312		1.2			(1.7	)		4.4
Wholesale
Non-affiliated		4,652		(7.3	)		(3.3	)		12.1
Affiliated		839		(43.6	)		44.9			(38.9	)
Total wholesale		5,491		(15.6	)		4.7			(1.5	)
Total energy sales		14,803		(5.8	)		0.8			2.0

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Residential energy sales decreased 1.4% in 2009 compared to 2008 due to the recessionary economy and a declining number of customers. Residential energy sales decreased 0.6% in 2008 compared to 2007 due to decreased customer usage mainly due to the recessionary economy and unfavorable summer weather. Residential energy sales increased 0.8% in 2007 compared to 2006, primarily due to more favorable weather conditions, which offset slow customer growth.

Commercial energy sales decreased 0.2% in 2009 compared to 2008 due to the recessionary economy and a net decline in commercial customers. Commercial energy sales decreased 0.7% in 2008 compared to 2007 due to unfavorable weather and slower than expected customer growth due to the economy. Commercial energy sales increased 7.5% in 2007 compared to 2006 due to customer growth mainly in the casino and hotel industries.

II-316

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Industrial energy sales increased 3.4% in 2009 compared to 2008 due to increased production of some of the Company’s industrial customers and the impacts of Hurricane Gustav, which negatively impacted industrial energy sales in 2008. Industrial energy sales decreased 3.0% in 2008 compared to 2007 due to lower customer use from the recessionary economy. Industrial energy sales increased 4.2% in 2007 compared to 2006 due to continued recovery after Hurricane Katrina.

Wholesale energy sales to non-affiliates decreased 7.3% and 3.3% and increased 12.1% in 2009, 2008, and 2007, respectively. Included in wholesale sales from sales to non-affiliates are sales from rural electric cooperative associations and municipalities located in southeastern Mississippi. Compared to the prior year, KWH sales to these customers remained at the same levels in 2009 despite the recessionary economy and unfavorable weather, decreased 0.9% in 2008 due to slowing growth and unfavorable weather, and increased 4.3% in 2007 due to growth in the service territory. KWH sales to non-territorial customers located outside the Company’s service territory decreased 29.0% in 2009 as compared to 2008 primarily due to fewer short-term opportunity sales related to lower gas prices. KWH sales to non-territorial customers located outside the Company’s service territory decreased 9.6% in 2008 as compared to 2007 primarily due to lower off-system sales. KWH sales to non-territorial customers increased 41.0% in 2007 as compared to 2006 primarily due to more off-system sales. Wholesale sales to non-affiliates will vary depending on the market cost of available energy compared to the cost of the Company and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.

Wholesale energy sales to affiliates decreased 43.6% in 2009 as compared to 2008 primarily due to a decrease in the Company’s generation and an increase in territorial sales, resulting in less capacity available to sell to affiliate companies. Wholesale energy sales to affiliates increased 44.9% in 2008 as compared to 2007 primarily due to the availability of the Company’s lower cost generation resources for sale to affiliated companies. Wholesale energy sales to affiliates decreased 38.9% in 2007 when compared to 2006 primarily due to a decrease in the Company’s generation and an increase in territorial sales, resulting in less capacity available to sell to affiliate companies.

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 generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market. Details of the Company’s electricity generated and purchased were as follows:

	2009		2008		2007
Total generation(millions of KWHs)		12,970		14,324		14,119
Total purchased power(millions of KWHs)		2,539		2,091		2,084
Sources of generation(percent)–
Coal		48		67		69
Gas		52		33		31
Cost of fuel, generated(cents per net KWH)–
Coal		4.29		3.52		2.92
Gas		4.43		6.83		6.25
Average cost of fuel, generated(cents per net KWH)		4.36		4.43		3.78
Average cost of purchased power(cents per net KWH)		3.62		6.05		4.60

Fuel and purchased power expenses were $611.6 million in 2009, a decrease of $101.4 million, or 14.2%, below the prior year costs. This decrease was primarily due to a $69.9 million decrease in the cost of fuel and purchased power and a $31.5 million decrease related to total KWHs generated and purchased. Fuel and purchased power expenses were $713.1 million in 2008, an increase of $122.9 million, or 20.8%, above the prior year costs. This increase was primarily due to a $116.5 million increase in the cost of fuel and purchased power and a $6.4 million increase related to total KWHs generated and purchased. Fuel and purchased power expenses were $590.1 million in 2007, an increase of $78.3 million, or 15.3%, above the prior year costs. This increase was primarily due to a $63.8 million increase in the cost of fuel and purchased power and a $14.5 million increase related to total KWHs generated and purchased.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Fuel expense decreased $66.8 million in 2009 as compared to 2008. Approximately $8.1 million of the reduction in fuel expenses resulted primarily from lower gas prices and a $58.7 million decrease in generation from Company-owned facilities. Fuel expense increased $92.2 million in 2008 as compared to 2007. Approximately $86.1 million in additional fuel expenses resulted from higher coal, gas, and transportation prices and a $6.1 million increase in generation from Company-owned facilities. Fuel expense increased $55.6 million in 2007 as compared to 2006. Approximately $56.8 million in additional fuel expenses resulted from higher coal, gas, transportation prices, and emissions allowances, which were partially offset by a $1.2 million decrease in generation from Company-owned facilities.

Purchased power expense decreased $34.6 million, or 27.4%, in 2009 when compared to 2008. The decrease was primarily due to a $61.8 million decrease in the cost of purchased power, partially offset by a $27.2 million increase in the amount of energy purchased which was due to lower cost opportunity purchases. Purchased power expense increased $30.7 million, or 32.0%, in 2008 when compared to 2007. The increase was primarily due to a $30.4 million increase in the cost of purchased power. Purchased power expense increased $22.6 million, or 30.9%, in 2007 when compared to 2006. The increase was primarily due to a $7.0 million increase in the cost of purchased power and a $15.6 million increase in the amount of energy purchased which was partially due to a decrease in generation resulting from plant outages. 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.

Coal prices continued to be influenced by worldwide demand from developing countries, as well as increased mining and fuel transportation costs. While coal prices reached unprecedented high levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices did not fully offset the higher priced coal already in inventory and under long-term contract. Demand for natural gas in the United States also was affected by the recessionary economy leading to significantly lower natural gas prices.

Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” and Note 1 to the financial statements under “Fuel Costs” for additional information.

Other Operations and Maintenance Expenses

Total other operations and maintenance expenses decreased $13.3 million in 2009 as compared to 2008 primarily due to a decrease of $12.2 million in transmission, distribution, customer service, and administrative and general expenses driven by overall reductions in spending in an effort to offset the effects of the recessionary economy. Also contributing to the decrease was an $8.3 million reduction in generation outage expenses in 2009. These decreases were partially offset by a $3.9 million increase in expenses for the combined cycle long-term service agreement due to a 36% increase in operating hours as a result of lower gas prices. Also offsetting the decrease was $3.4 million resulting from the 2008 reclassification of generation construction screening expenses to a regulatory asset upon the FERC’s acceptance of the wholesale filing in October 2008.

Total other operations and maintenance expenses increased $4.8 million in 2008 as compared to 2007 primarily due to a $6.9 million increase in transmission and distribution expenses, an increase in administrative expenses primarily resulting from the reclassification of System Restoration Rider (SRR) revenues of $3.8 million to expense pursuant to an order from the Mississippi PSC dated January 9, 2009, a $1.9 million increase in generation-related environmental expenses, and a $1.1 million increase in generation operations and outage-related expenses. These increases were partially offset by a $9.3 million reclassification of generation construction screening expenses to a regulatory asset upon the FERC’s acceptance of the wholesale filing in October 2008.

Total other operations and maintenance expenses increased $18.6 million from 2006 to 2007. Other operations expense increased $15.1 million, or 8.8%, in 2007 compared to 2006 primarily as a result of a $4.1 million increase in generation construction screening, a $3.3 million insurance recovery for storm restoration expense recognized in 2006, a $2.1 million increase in employee benefits primarily due to an increase in medical expense, a $2.0 million increase in outside and other contract services, and a $2.0 million increase in scheduled production projects. Maintenance expense increased $3.5 million, or 5.2%, in 2007 when compared to 2006, primarily as a result of a $5.5 million increase in generation maintenance expense primarily due to outage work in 2007, partially offset by a $2.0 million decrease in transmission and distribution maintenance expenses due primarily to the deferral of these expenses pursuant to the regulatory accounting order from the Mississippi PSC.

See FUTURE EARNINGS POTENTIAL — “FERC Matters,” “PSC Matters — System Restoration Rider,” and “PSC Matters — Storm Damage Cost Recovery” herein for additional information.

II-318

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Depreciation and Amortization

Depreciation and amortization expenses decreased $0.1 million in 2009 compared to 2008 primarily due to a $3.1 million decrease in amortization of environmental costs related to the approved ECO Plan, partially offset by a $2.8 million increase in depreciation expense resulting from an increase in plant in service. Depreciation and amortization expenses increased $10.7 million in 2008 compared to 2007 primarily due to a $5.7 million increase in amortization related to a regulatory liability recorded in 2003 that ended in December 2007 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity, a $2.9 million increase in depreciation expense primarily due to an increase in plant in service, and a $2.4 million increase for amortization of certain reliability-related maintenance costs deferred in 2007 in accordance with a Mississippi PSC order. Depreciation and amortization expenses increased $13.5 million in 2007 compared to 2006 due to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on Plant Daniel capacity and an increase in amortization of environmental costs related to the approved ECO Plan. See Note 3 under “Retail Regulatory Matters – Performance Evaluation Plan” and “Environmental Compliance Overview Plan” for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1.0 million in 2009 compared to 2008 primarily as a result of a $0.8 million decrease in payroll taxes and a $0.2 million decrease in franchise taxes. Taxes other than income taxes increased $4.8 million in 2008 compared to 2007 primarily as a result of a $2.7 million increase in ad valorem taxes and a $1.3 million increase in municipal franchise taxes. Taxes other than income taxes decreased $0.6 million in 2007 compared to 2006 primarily as a result of a $2.0 million decrease in ad valorem taxes, partially offset by a $1.5 million increase in municipal franchise taxes.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $5.0 million in 2009 compared to 2008 primarily due to a $5.2 million increase in interest expense associated with the issuance of new long-term debt in November 2008 and March 2009, partially offset by the maturity of long-term debt and lower interest rates in 2009. Interest expense, net of amounts capitalized decreased $0.2 million in 2008 compared to 2007 primarily due to a $2.7 million decrease in borrowing and lower interest rates on short-term indebtedness and a $0.7 million decrease related to the redemption of outstanding trust preferred securities in 2007, partially offset by a $3.0 million increase in interest expense associated with the issuance of new long-term debt in November 2008 and November 2007. Interest expense, net of amounts capitalized decreased $0.5 million in 2007 compared to 2006 due to a $1.3 million decrease in long-term debt primarily related to the redemption of outstanding trust preferred securities, partially offset by the issuance of new long-term debt in November 2007 and a $0.7 million increase in short-term debt borrowing net of amounts related to Hurricane Katrina.

Other Income (Expense), Net

Other income (expense), net decreased $1.7 million in 2009 compared to 2008 primarily due to a $3.0 million decrease in customer projects and amounts collected from customers for construction of substation projects which had a tax effect of $2.6 million, partially offset by higher charitable contributions of $3.9 million in 2008. Other income (expense), net decreased $1.3 million in 2008 compared to 2007 primarily due to higher charitable contributions of $3.1 million, partially offset by a $0.4 million increase in revenues from contracting work performed for customers, a $0.6 million decrease in other deductions, and a $0.6 million increase in allowance for equity funds used during construction. Other income (expense), net increased $12.7 million in 2007 compared to 2006 primarily due to higher charitable contributions of $6.9 million in 2006 as compared to 2007, a gain on a contract termination approved by the FERC in 2007 of $3.7 million, and an increase in customer projects of $2.5 million.

Income Taxes

Income taxes increased $1.9 million, or 3.9%, in 2009 primarily due to increased pre-tax income, the 2008 amortization of a regulatory liability pursuant to a December 2007 regulatory accounting order from the Mississippi PSC which occurred in 2008, and actualization of permanent differences from previous year tax returns, partially offset by an increase in the federal production activities deduction and an increase in a State of Mississippi manufacturing investment tax credit. Income taxes decreased $3.4 million, or 6.7%, in 2008 primarily due to decreased pre-tax income, the amortization of a regulatory liability pursuant to a December 2007 regulatory accounting order from the Mississippi PSC, and a State of Mississippi manufacturing investment tax credit, partially offset by a decrease in the federal production activities deduction. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information. Income taxes increased $3.7 million, or 7.8%, in 2007 primarily due to increased pre-tax income and lower federal and state tax credits. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

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Mississippi Power Company 2009 Annual Report

Effects of Inflation

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company’s results of operations has not been substantial.

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 to wholesale customers in the southeast United States. 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. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated 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 regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s primary business of selling electricity. These factors include the Company’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining 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 or decline in the Company’s service area. Recessionary conditions have negatively impacted sales. The timing and extent of the economic recovery will impact future earnings.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may exceed amounts estimated. Some of the factors driving the potential for such an increase are higher commodity costs, market demand for labor, and scope additions and clarifications. The timing, specific requirements, and estimated costs could also change as environmental statutes and regulations are adopted or modified. See Note 3 to the financial statements under “Environmental Matters” for additional information.

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. These actions were filed concurrently with the issuance of notices of violations to the Company with respect to the Company’s Plant Watson. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. In early 2000, the EPA filed a motion to amend its complaint to add the Company as a defendant based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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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 $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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; the Endangered Species Act; and related federal and state regulations. 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 2009, the Company had invested approximately $224 million in capital projects to comply with these requirements, with annual totals of $22 million, $41 million, and $17 million for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $11 million, $59 million, and $128 million for 2010, 2011, and 2012, respectively. The Company’s compliance strategy can be affected by changes to existing environmental laws, statutes, and regulations; the cost, availability, and existing inventory of emissions allowances; and the Company’s fuel mix. 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 any new federal or state legislation or regulations related to global climate change, air quality, coal combustion byproducts, including coal ash, or other environmental and health concerns could also significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company’s operations, 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 2009, the Company had spent approximately $107 million in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls are currently being installed at several plants to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality standard. No area within the Company’s service area is currently designated as nonattainment under the eight-hour ozone standard. In March 2008, however, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to finalize the revised standard in August 2010 and require state implementation plans for any nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result in designation of new nonattainment areas within the Company’s service territory.

On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard for SO₂. The EPA is expected to finalize the revised SO₂ standard in June 2010.

Twenty-eight eastern states, including the States of Mississippi and Alabama, are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place while the EPA develops a revised rule. The States of Mississippi and Alabama have completed plans to implement CAIR, and emissions reductions are being accomplished by the installation of emissions controls at the Company’s coal-fired facilities and/or by the purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in July 2010.

The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring 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) to certain sources built between 1962 and 1977, and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural conditions goal by 2018 and for each ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and NO_x, and no additional controls beyond CAIR are anticipated to be necessary at any of the Company’s facilities. States have completed or are currently completing implementation plans for BART compliance and other measures required to achieve the first phase of reasonable progress.

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The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants, including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and trade program for the reduction of mercury emissions from coal-fired power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.

The impacts of the eight-hour ozone standards and future revisions to CAIR, the SO₂ standard, the Clean Air Visibility Rule, and the MACT rule for electric generating units on the Company cannot be determined at this time and will depend on the specific provisions of the final rules, resolution of any legal challenges, and the development and implementation of rules at the state level. However, these additional regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂and NO_x emissions controls within the next several years to ensure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing intake structures. The EPA is now in the process of revising the regulations. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on further rulemaking by the EPA and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

On December 28, 2009, the EPA announced its determination that revision of the current effluent guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions by 2013. New wastewater treatment requirements are expected and may result in the installation of additional controls on certain Company facilities. The impact of revised guidelines will depend on the studies conducted in connection with the rulemaking, as well as the specific requirements of the final rule, 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 releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its 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 Company could 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.

Coal Combustion Byproducts

The EPA is currently evaluating whether additional regulation of coal combustion byproducts is merited under federal solid and hazardous waste laws. The EPA has collected information from the electric utility industry on surface impoundment safety and conducted on-site inspections at three Southern Company system facilities as part of its evaluation. The Company has a routine and robust inspection program in place to ensure the integrity of its coal ash surface impoundments. The EPA is expected to issue a proposal regarding additional regulation of coal combustion byproducts in early 2010. The impact of these additional regulations on the Company will depend on the specific provisions of the final rule and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the Company’s management, beneficial use, and disposal of such byproducts and could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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Mississippi Power Company 2009 Annual Report

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. These costs could affect future unit retirement and replacement decisions, and could result in the retirement of a significant number of coal-fired generating units. See Item 1 — BUSINESS — “Rate Matters — Integrated Resource Planning” for additional information. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 12 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 10 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. These include proposed construction of an advanced integrated coal gasification combined cycle (IGCC) unit with approximately 65% carbon capture in Kemper County, Mississippi.

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FERC Matters

In August 2008, the Company filed with the FERC a request for revised wholesale electric tariff and rates. Prior to making this filing, the Company reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provided for an increase in annual base wholesale revenues in the amount of $5.8 million, effective January 1, 2009. In addition, the settlement agreement allows the Company to increase its annual accrual for the wholesale portion of property damage to $303,000 per year, to defer any property damage costs prudently incurred in excess of the wholesale property damage reserve balance, and to defer the wholesale portion of the generation screening and evaluation costs associated with the IGCC project to be located in Kemper County Mississippi. The settlement agreement also provided that the Company will not seek a change in wholesale
full-requirements rates before November 1, 2010, except for changes associated with the fuel adjustment clause and the energy cost management clause (ECM), changes associated with property damages that exceed the amount in the wholesale property damage reserve, and changes associated with costs and expenses associated with environmental requirements affecting fossil fuel generating facilities. In October 2008, the Company received notice that the FERC had accepted the filing effective November 1, 2008, and the revised monthly charges were applied beginning January 1, 2009. As result of the order, the Company reclassified $9.3 million of previously expensed generation screening and evaluation costs to a regulatory asset. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

PSC Matters

Statewide Electric Generation Needs Review

In April 2008, in accordance with the Mississippi Public Utility Act, the Mississippi PSC issued an order to develop, publicize, and keep current an analysis of the five-year long-range needs for expansion of facilities for the generation of electricity in the State of Mississippi. In its order, the Mississippi PSC directed all affected utilities to submit evidence in support of their forecasts and plans in accordance with the rules of the Mississippi PSC. On January 16, 2009, the Company filed for a request for a Certificate of Public Convenience to construct generating capacity. On August 4, 2009, the Mississippi PSC ordered a two-part hearing process to evaluate the need for and the resources and cost of the new generating capacity separately. On November 9, 2009, the Mississippi PSC ordered that the need for new generating capacity existed. Hearings related to the appropriate resource to meet that need as well as cost recovery of that resource through application of the Baseload Act (described below) were held in February 2010. A decision on the resources and cost is expected to be made by May 1, 2010. The ultimate outcome of this matter cannot now be determined. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

Mississippi Baseload Construction Legislation

In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the Governor in May 2008 to enhance the Mississippi PSC’s authority to facilitate development and construction of base load generation in the State of Mississippi (Baseload Act). The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. The effect of this legislation on the Company cannot now be determined.

Performance Evaluation Plan

In May 2004, the Mississippi PSC approved the Company’s request to reclassify 266 megawatts (MWs) 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. In the May 2004 order establishing the Company’s forward-looking PEP, the Mississippi PSC ordered that the Mississippi Public Utilities Staff and the Company review the operations of the PEP in 2007. By mutual agreement, this review was deferred until 2008 and continued into 2009. On March 2, 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. On August 3, 2009, the Mississippi Public Utilities Staff and the Company filed a joint report with the Mississippi PSC proposing

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several changes to the PEP. On November 9, 2009, the Mississippi PSC approved the revised PEP, which resulted in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. On November 16, 2009, the Company resumed annual evaluations and filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change.

In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2009, the Company had a balance of the deferred retail portion of $4.7 million with $2.3 million included in current assets as other regulatory assets and $2.4 million included in long-term other regulatory assets. See Note 3 to the financial statements under “Retail Regulatory Matters — Performance Evaluation Plan” for more information on PEP.

System Restoration Rider

In September 2006, the Company filed with the Mississippi PSC a request to implement a SRR to increase the Company’s cap on the property damage reserve and to authorize the calculation of an annual property damage accrual based on a formula. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. In November 2007, the Company along with the Mississippi Public Utilities Staff agreed and stipulated to a revised SRR calculation method that would no longer require the Mississippi PSC to set a cap on the property damage reserve or to authorize the calculation of an annual property damage accrual. Under the revised SRR calculation method, the Mississippi PSC would periodically agree on SRR revenue levels that would be developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information.

On January 9, 2009, the Mississippi PSC issued an order accepting the stipulation and the revised SRR calculation method. The applicable SRR rate level will be adjusted every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be appropriate. The Company will submit annual filings setting forth SRR-related revenues, expenses, and investment for the projected filing period, as well as the true-up for the prior period. As a result, the December 2008 retail regulatory liability of $6.8 million was reclassified to the property damage reserve. On February 2, 2009, the Company submitted its 2009 SRR rate filing with the Mississippi PSC, which proposed that the 2009 SRR rate level remain at zero and the Company be allowed to accrue approximately $4.0 million to the property damage reserve in 2009. On September 10, 2009, the Mississippi PSC issued an order requiring Mississippi Power to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million from November 2009 to March 2010 under the new rate. On January 29, 2010, the Company submitted its 2010 SRR rate filing with the Mississippi PSC, which proposed that the Company be allowed to accrue approximately $3.0 million to the property damage reserve in 2010. The final outcome of this matter cannot now be determined.

Environmental Compliance Overview Plan

On February 12, 2010, the Company submitted its 2010 ECO Plan notice which proposes an increase in annual revenues for the Company of approximately $3.9 million. In its 2010 ECO filing, the Company is proposing to change the true-up provision of the ECO rate schedule to consider actual revenues collected in addition to actual costs. The final outcome of this matter cannot now be determined. On February 3, 2009, the Company submitted its 2009 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $1.5 million. On June 19, 2009, the Mississippi PSC approved the ECO Plan with the new rates effective in June 2009.

Fuel Cost Recovery

The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2009. The Mississippi PSC approved the retail fuel cost recovery factor on December 15, 2009, with the new rates effective in January 2010. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 11.3% of total 2009 retail revenue. At December 31, 2009, the amount of over recovered retail fuel costs included in the balance sheets was $29.4 million compared to $36.0 million under recovered at December 31, 2008. The Company also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2010, the wholesale MRA fuel rate decreased, resulting in an

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Mississippi Power Company 2009 Annual Report

annual decrease in an amount equal to 20.9% of total 2009 MRA revenue. Effective February 1, 2010, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 16.9% of total 2009 MB revenue. At December 31, 2009, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $16.8 million and $2.4 million compared to $15.4 million and $3.7 million, respectively, under recovered at December 31, 2008. 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 decrease to the billing factor will have no significant effect on the Company’s revenues or net income, but will decrease annual cash flow.

In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including the Company. On March 4, 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. On May 20, 2009, the Company filed the carrying cost calculation methodology as part of its compliance filing.

In August 2009, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company’s fuel-related expenditures included in the fuel adjustment clause and the ECM clause of 2008 and 2009. The audit was completed in December 2009. There were no audit findings identified in the audit.

Storm Damage Cost Recovery

In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 were $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million. Such costs were affirmed by the Mississippi PSC in June 2006, and the Company was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing the Company to file an application with the Mississippi Development Authority (MDA) for a Community Development Block Grant (CDBG). In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. These funds were received in June 2007. The Company affirmed the $302.4 million total storm costs incurred as of December 31, 2007. On March 2, 2009, the Company filed with the Mississippi PSC its final accounting of the restoration cost relating to Hurricane Katrina and the storm operations center. The final net retail receivable of approximately $3.2 million is expected to be recovered in 2010.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of the Company. The Company’s cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA was approximately $14 million. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of the Company.

On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $25 million related to the Company, under the ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. The Company continues to assess the other financial implications of the ARRA.

The U.S. House of Representatives and the U.S. Senate have passed separate bills related to healthcare reform. Both bills include a provision that would make Medicare Part D subsidy reimbursements taxable. If enacted into law, this provision could have a significant negative impact on the Company’s net income. See Note 2 to the financial statements under “Other Postretirement Benefits” for additional information.

The ultimate impact of these matters cannot be determined at this time.

Income Tax Matters

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code of 1986, as amended. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years

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Mississippi Power Company 2009 Annual Report

2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Integrated Coal Gasification Combined Cycle

On January 16, 2009, the Company filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. The plant would utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize the Company to acquire, construct, and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, the Company has requested certain rate recovery treatment in accordance with the Baseload Act.

The Company filed an application in June 2006 with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the Kemper IGCC, and in November 2006 the IRS allocated Internal Revenue Code Section 48A tax credits of $133 million to the Company. On May 11, 2009, the Company received notification from the IRS formally certifying these tax credits. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014. The Company has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for the Section 48A credits.

In February 2008, the Company also requested that the DOE transfer the remaining funds previously granted to a cancelled Southern Company project that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds to the Kemper IGCC. The estimated construction cost of the Kemper IGCC is approximately $2.4 billion, which is net of $245 million related to funding to be received from the DOE related to project construction. The remaining DOE funding of $25 million is projected to be used for demonstration over the first few years of operation.

On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. The Company expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law.

Beginning in December 2006, the Mississippi PSC has approved the Company’s requested accounting treatment to defer the costs associated with the Company’s generation resource planning, evaluation, and screening activities as a regulatory asset. In December 2008, the Company requested an amendment to its original order that would allow these costs to continue to be charged to and remain in a regulatory asset until January 1, 2010. On April 6, 2009, the Company received an accounting order from the Mississippi PSC directing the Company to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of the Company’s prudent expenditures. The Mississippi PSC’s determination of prudence for the Company’s pre-construction costs is scheduled to occur by May 2010. As of December 31, 2009, the Company had spent a total of $73.5 million associated with the Company’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the year ended December 31, 2009 totaled $31.2 million as compared to $24.2 million for the year ended December 31, 2008. Of the total $73.5 million, $68.5 million was deferred in other regulatory assets, $4.0 million was related to land purchases capitalized, and $1.0 million was expensed.

On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. On August 4, 2009, the Mississippi PSC ordered a two-part hearing process to evaluate the need for and the resources and cost of the new generating capacity separately. On November 9, 2009, the Mississippi PSC issued an order that found the Company has a demonstrated need for additional capacity of approximately 304 MWs to 1,276 MWs based on an analysis of expected load forecasts, costs, and anticipated retirements. Hearings related to the appropriate resource to meet that need as well as cost recovery of that resource through application of the Baseload Act were held in February 2010. A decision on the resources and cost recovery is expected to be made by May 1, 2010.

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Mississippi Power Company 2009 Annual Report

On September 15, 2009, South Mississippi Electric Power Association (SMEPA) signed a non-binding letter of intent to explore the acquisition of an interest in the Kemper IGCC. The Company and SMEPA are evaluating a combination of a joint ownership arrangement and a power purchase agreement which would provide SMEPA with up to 20% of the capacity and associated energy output from the Kemper IGCC.

The final outcome of this matter cannot now be determined.

Other Matters

In February 2008, the Company received notice of termination from SMEPA of an approximately 100 MW territorial wholesale market-based contract effective March 31, 2011 which will result in a decrease in annual revenues of approximately $12 million. In December 2008, the Company entered into a 10-year power supply agreement with SMEPA for approximately 152 MWs. This contract is effective April 1, 2011, upon approval from the U.S. Department of Agriculture’s Rural Utilities Service. This contract is expected to increase the Company’s annual territorial wholesale base revenues by approximately $16.1 million. On June 3, 2009, Mississippi Power’s 10-year power supply agreement with SMEPA for approximately 152 MWs effective April 1, 2011 was approved by the U.S. Department of Agriculture’s Rural Utilities Service.

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury, and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require 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 the accounting standards 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Contingent Obligations

The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and, in accordance with generally accepted accounting principles (GAAP), records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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, coal combustion byproducts, including coal ash, control of toxic substances, hazardous and solid wastes, and other environmental matters.

• Changes in existing income tax regulations or changes in IRS or state revenue department 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 new or other potential lawsuits or complaints in which the Company may be named as a defendant.

• Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA.

Unbilled Revenues

Revenues related to the retail 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.

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-MW 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; and

• Juniper’s status as a voting interest entity.

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Mississippi Power Company 2009 Annual Report

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 is also 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 $26 million.

Pension and Other Postretirement Benefits

The Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, health care cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on the Company’s investment strategy, historical experience, and expectations for long-term rates of return that considers external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company’s target asset allocation. The Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption would result in a $0.7 million or less change in the total benefit expense and a $13 million or less change in projected obligations.

New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance of the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted this new guidance effective January 1, 2010, with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2009. Throughout the turmoil in the financial markets, the Company has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and the Company has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees for the Company average less than¹/4 of 1% per year. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. See “Sources of Capital” and “Financing Activities” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

The Company’s investments in pension trust funds remained stable as of December 31, 2009. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities in 2009 increased from 2008 by $76.2 million. The increase in net cash provided from operating activities was primarily due to an increase in cash related to higher fuel rates effective in March 2009 and a decrease in deferred income taxes. Net cash provided from operating activities in 2008 decreased from 2007 by $112.2 million. The decrease in net cash provided from operating activities was primarily due to the receipt of grant proceeds of $74.3 million in June 2007 and a decrease in operating activities related to receivables in 2008 in the amount of $49.5 million. The decrease in receivables is primarily due to the change in under recovered regulatory clause revenues of $24.7 million and a $24.1 million change in affiliate receivables. Also impacting operating activities were decreases related to fossil fuel stock of $33.3 million primarily due to increases in coal and coal in-transit of $22.0 million and $15.6 million, respectively. These were offset by an increase in deferred income taxes and investment tax credits of $61.4 million. Net cash provided from operating activities increased in 2007 compared to 2006 by $11.7 million primarily due to the Company’s receipt of $74.3 million in bond proceeds during 2007 related to Hurricane Katrina recovery, of which $60 million was used to fund the property damage reserve and $14.3 million was used to recover retail operations and maintenance storm restoration cost.

Net cash used for investing activities totaled $119.4 million for 2009 compared to $155.8 million for 2008. The $36.4 million decrease was primarily due to a decrease in property additions. The $55.3 million increase in net cash used for investing activities in 2008 was primarily due to a $12.1 million increase in construction payables and a $27.6 million increase due to the capital portion of Hurricane Katrina grant proceeds received in 2007. The change in net cash used for investing activities in 2007 compared to 2006 of $107.0 million was primarily due to a $117.8 million reduction in the sources of funds related to Hurricane Katrina capital-related grant proceeds received in 2006 and bond proceeds.

Net cash used for financing activities totaled $8.6 million in 2009 compared to $78.9 million that was provided from financing activities in 2008. The $87.5 million decrease was primarily due to a $42.6 million decrease in notes payable and a $40 million decrease in long-term debt as a result of a March 2009 senior note redemption, when compared to the corresponding period in 2008. Net cash provided from financing activities totaled $78.9 million in 2008 compared to $105.5 million that was used in financing activities for the corresponding period in 2007. The $184.5 million increase in net cash provided from financing activities was primarily due to the $80 million long-term bank loan issued to the Company in March 2008, the $50 million senior notes issued in November 2008, and the $36 million redemption of the long-term debt to an affiliated trust in the first nine months of 2007. Notes payable increased by $57.8 million primarily due to additional borrowings from commercial paper. Net cash used for financing activities totaled $105.5 million in 2007 compared to $211.5 million in 2006. This decrease in net cash used for financing activities is primarily due to a decrease in the use of funds related to notes payable of $109.3 million.

Significant changes in the balance sheet as of December 31, 2009 compared to 2008 include an increase in cash of $42.6 million. Under recovered regulatory clause revenues decreased by $55.0 million primarily due to lower fuel costs and the implementation of higher fuel rates in 2009. Fossil fuel inventory increased $41.7 million primarily due to increases in coal inventory and emissions allowances of $30.1 million and $11.6 million, respectively. Prepaid income taxes increased by $31.2 million and total property, plant, and equipment increased by $32.4 million. Other regulatory assets, deferred increased by $37.4 million primarily due to the increase in spending related to the Kemper IGCC. Securities due within one year decreased $39.9 million primarily due to senior notes maturing during the first quarter 2009. Notes payable decreased by $26.3 million primarily due to a decrease in commercial paper borrowings. Over recovered regulatory clause liabilities increased by $48.6 million primarily due to lower fuel costs and the implementation of higher fuel rates in 2009. Long-term debt increased by $123.0 million primarily due to the issuance of senior notes in the first quarter 2009. Employee benefit obligations increased $19.6 million primarily due to the decline in the market value of pension assets. See Note 2 to the financial statements under “Pension Plans” for additional information.

The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, decreased from 61.2% in 2008 to 55.6% at December 31, 2009. The Company has received investment grade credit ratings from the major rating agencies with respect to debt and preferred stock. See SELECTED FINANCIAL AND OPERATING DATA for additional information regarding the Company’s security ratings. See “Credit Rating Risk” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Sources of Capital

The Company plans to obtain the funds required for construction and other purposes from sources such as operating cash flows, security issuances, term loans, short-term borrowings, and capital contributions from Southern Company. See “Capital Requirements and Contractual Obligations” herein and Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. The amount, type, and timing of any financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.

The issuance of securities by the Company is subject to regulatory approval by the FERC. 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, as amended (1933 Act). The amounts of securities authorized by the FERC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company.

To meet short-term cash needs and contingencies, the Company has various sources of liquidity. At December 31, 2009, the Company had approximately $65 million of cash and cash equivalents and $156 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 at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company and are not commingled with proceeds from such issuances for the benefit of any other operating company. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2009, the Company had no commercial paper outstanding.

Financing Activities

During the first quarter of 2009, the Company issued senior notes totaling $125 million. Proceeds were used to repay at maturity the Company’s $40 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009 and to repay a portion of the Company’s short-term indebtedness.

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 2001, the Company began an initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel. 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% 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 renewal and a purchase 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 4% of the initial acquisition cost over the initial lease term. In April 2010, 18 months prior to the end of the initial lease, the Company must notify Juniper if the lease will be terminated. The Company may elect to renew the lease for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17% 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% 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. See Note 7 to the financial statements under “Operating Leases — Plant Daniel Combined Cycle Generating Units” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At December 31, 2009, the maximum potential collateral requirements under these contracts at BBB- and/or Baa3 rating were approximately $5 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $370 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

On September 2, 2009, Moody’s Investors Service (Moody’s) affirmed the credit ratings of the Company’s senior unsecured notes and commercial paper of A1/P-1, respectively, and revised the rating outlook for the Company to negative. On September 4, 2009, Fitch Ratings, Inc. affirmed the Company’s senior unsecured notes and commercial paper ratings of AA-/F1+, respectively, and maintained a stable rating outlook for the Company. On October 6, 2009, Standard and Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc. (S&P) affirmed the credit rating of the Company’s senior unsecured notes and its short-term rating of A/A-1, respectively, and maintained its stable ratings outlook.

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, where possible, 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. The Company’s 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, value at risk, stress testing, and sensitivity analysis.

The Company does not currently hedge interest rate risk. The weighted average interest rate on $120 million of variable rate long-term debt at January 1, 2010 was 0.54%. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $1.2 million at January 1, 2010.

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, 2009, exposure from these activities was not material to the Company’s financial statements.

In addition, per the guidelines of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2009, exposure from these activities was not material to the Company’s financial statements.

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

	2009			2008
	Changes			Changes
	Fair Value
	(in thousands)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(51,985	)	$	1,978
Contracts realized or settled		53,905			(30,639	)
Current period changes(a)		(43,654	)		(23,324	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(41,734	)	$	(51,985	)

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

II-334

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

The change in the fair value positions of the energy-related derivative contracts for the year ended December 31, 2009 was an increase of $10.3 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of million British thermal units (mmBtu) and prices of natural gas. At December 31, 2009, the Company had a net hedge volume of 23.7 million mmBtu with a weighted average contract cost of approximately $1.80 per mmBtu above market prices, and 28.9 million mmBtu at December 31, 2008 with a weighted average contract cost of approximately $1.89 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the ECM clause.

At December 31, 2009, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows:

Asset (Liability) Derivatives	2009			2008
	(in thousands)
Regulatory hedges	$	(41,746	)	$	(51,956	)
Cash flow hedges		—			142
Not designated		12			(171	)
Total fair value	$	(41,734	)	$	(51,985	)

Energy-related derivative contracts which are designated as regulatory hedges relate to the Company’s fuel hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause. Gains and losses on energy-related derivatives designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. The pre-tax gains/(losses) reclassified from other comprehensive income to revenue and fuel expense were not material for any period presented and are not expected to be material for 2010. Additionally, there was no material ineffectiveness recorded in earnings for any period presented.

Unrealized pre-tax gains/(losses) from energy-related derivative contracts recognized in income were not material for any year presented.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in thousands)
Level 1	$	—		$	—		$	—		$	—
Level 2		(41,734	)		(18,996	)		(22,600	)		(138	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(41,734	)	$	(18,996	)	$	(22,600	)	$	(138	)

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 9 to the financial statements for further discussion on fair value measurement.

The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P 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 Note 1 to the financial statements under “Financial Instruments” and Note 10 to the financial statements.

II-335

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $472 million for 2010, $661 million for 2011, and $1.3 billion for 2012. These estimates include costs for new generation construction. Environmental expenditures included in these estimated amounts are $11 million, $59 million, and $128 million for 2010, 2011, and 2012, respectively. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

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 FERC.

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, 7, and 10 to the financial statements for additional information.

II-336

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(d)		Total
	(in thousands)
Long-term debt(a) —
Principal	$	—	$	80,000	$	50,000	$	362,694	$	—	$	492,694
Interest		21,643		42,479		38,761		202,726		—		305,609
Preferred stock dividends(b)		1,733		3,465		3,465		—		—		8,663
Energy-related derivative obligations(c)		19,454		22,641		202		—		—		42,297
Unrecognized tax benefits and interest(d)		290		—		—		—		2,967		3,257
Operating leases (e)		40,326		47,588		17,441		1,613				106,968
Capital leases(f)		1,330		2,070		—		—		—		3,400
Purchase commitments(g) —
Capital(h)		471,511		1,935,149		—		—		—		2,406,660
Coal		316,006		434,084		30,805		—		—		780,895
Natural gas(i)		185,120		251,804		137,330		182,662		—		756,916
Long-term service agreements(j)		13,159		27,201		28,097		74,518		—		142,975
Postretirement benefits trust(k)		230		459		—		—		—		689
Total	$	1,070,802	$	2,846,940	$	306,101	$	824,213	$	2,967	$	5,051,023

(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, 2010, as reflected in the statements of capitalization. Excludes capital lease amounts (shown separately).
(b)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c)	For additional information, see Notes 1 and 10 to the financial statements.
(d)	The timing related to the realization of $3 million in unrecognized tax benefits and interest payments in individual years beyond 12 months cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information.
(e)	The decrease from 2011-2012 to 2013-2014 is primarily a result of the Plant Daniel operating lease contract that is scheduled to end during 2011. See Note 7 to the financial statements for additional information.
(f)	The capital lease of $6.4 million is being amortized over a five-year period ending in 2012.
(g)	The Company generally does not enter into non-cancelable commitments for other operations and maintenance expenditures. Total other operations and maintenance expenses for 2009, 2008, and 2007 were $247 million, $260 million, and $255 million, respectively.
(h)	The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program.
(i)	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, 2009.
(j)	Long-term service agreements include price escalation based on inflation indices.
(k)	The Company forecasts postretirement trust contributions over a three-year period. The Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Therefore, no amounts related to the pension trust fund are included in the table. 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-337

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, access to sources of capital, projections for postretirement benefit trust contributions, financing activities, start and completion of construction projects, impacts of adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and purchases under new power sale and purchase agreements, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, or coal combustion byproducts and other substances and also changes in 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, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• 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 actions relating to fuel and other cost recovery mechanisms;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generation resources;

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

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

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

II-338

STATEMENTS OF INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Mississippi Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Revenues:
Retail revenues	$	790,950		$	785,434		$	727,214
Wholesale revenues, non-affiliates		299,268			353,793			323,120
Wholesale revenues, affiliates		44,546			100,928			46,169
Other revenues		14,657			16,387			17,241
Total operating revenues		1,149,421			1,256,542			1,113,744
Operating Expenses:
Fuel		519,687			586,503			494,248
Purchased power, non-affiliates		8,831			27,036			9,188
Purchased power, affiliates		83,104			99,526			86,690
Other operations and maintenance		246,758			260,011			255,177
Depreciation and amortization		70,916			71,039			60,376
Taxes other than income taxes		64,068			65,099			60,328
Total operating expenses		993,364			1,109,214			966,007
Operating Income		156,057			147,328			147,737
Other Income and (Expense):
Interest income		804			1,998			1,986
Interest expense, net of amounts capitalized		(22,940	)		(17,979	)		(18,158	)
Other income (expense), net		2,993			4,695			6,029
Total other income and (expense)		(19,143	)		(11,286	)		(10,143	)
Earnings Before Income Taxes		136,914			136,042			137,594
Income taxes		50,214			48,349			51,830
Net Income		86,700			87,693			85,764
Dividends on Preferred Stock		1,733			1,733			1,733
Net Income After Dividends on Preferred Stock	$	84,967		$	85,960		$	84,031

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

II-339

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009, 2008, and 2007
Mississippi Power Company 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Activities:
Net income	$	86,700		$	87,693		$	85,764
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		78,914			75,765			69,971
Deferred income taxes		(39,849	)		24,840			(36,572	)
Plant Daniel capacity		—			—			(5,659	)
Pension, postretirement, and other employee benefits		7,077			8,182			8,782
Stock based compensation expense		886			724			1,038
Tax benefit of stock options		34			489			287
Generation construction screening costs		(30,638	)		(26,662	)		(9,031	)
Hurricane Katrina grant proceeds-property reserve		—			—			60,000
Other, net		(3,650	)		(20,767	)		(15,784	)
Changes in certain current assets and liabilities —
-Receivables		9,677			(9,982	)		14,874
-Under recovered regulatory clause revenues		54,994			(14,450	)		10,234
-Fossil fuel stock		(41,699	)		(38,072	)		(4,787	)
-Materials and supplies		(649	)		297			487
-Prepaid income taxes		1,061			3,243			17,726
-Other current assets		2,065			(2,022	)		(1,923	)
-Hurricane Katrina grant proceeds		—			—			14,345
-Hurricane Katrina accounts payable		—			—			(53	)
-Other accounts payable		(7,590	)		3,251			(4,525	)
-Accrued taxes		8,800			2,428			(867	)
-Accrued compensation		(6,819	)		(1,362	)		(1,993	)
-Over recovered regulatory clause revenues		48,596			—			—
-Other current liabilities		2,732			836			4,344
Net cash provided from operating activities		170,642			94,431			206,658
Investing Activities:
Property additions		(101,995	)		(153,401	)		(144,925	)
Cost of removal net of salvage		(9,352	)		(6,411	)		2,195
Construction payables		(5,091	)		(4,084	)		8,027
Hurricane Katrina capital grant proceeds		—			7,314			34,953
Other investing activities		(2,971	)		819			(755	)
Net cash used for investing activities		(119,409	)		(155,763	)		(100,505	)
Financing Activities:
Increase (decrease) in notes payable, net		(26,293	)		16,350			(41,433	)
Proceeds —
Capital contributions from parent company		4,567			3,541			5,436
Gross excess tax benefit of stock options		117			934			572
Pollution control revenue bonds		—			7,900			—
Senior notes issuances		125,000			50,000			35,000
Other long-term debt issuances		—			80,000			—
Redemptions —
Pollution control revenue bonds		—			(7,900	)		—
Senior notes		(40,000	)		—			—
Other long-term debt		—			—			(36,082	)
Payment of preferred stock dividends		(1,733	)		(1,733	)		(1,733	)
Payment of common stock dividends		(68,500	)		(68,400	)		(67,300	)
Other financing activities		(1,779	)		(1,774	)		—
Net cash provided from (used for) financing activities		(8,621	)		78,918			(105,540	)
Net Change in Cash and Cash Equivalents		42,612			17,586			613
Cash and Cash Equivalents at Beginning of Year		22,413			4,827			4,214
Cash and Cash Equivalents at End of Year	$	65,025		$	22,413		$	4,827
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $117, $229 and $12 capitalized, respectively)	$	19,832		$	15,753		$	16,164
Income taxes (net of refunds)		77,206			23,829			67,453

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

II-340

BALANCE SHEETS
At December 31, 2009 and 2008
Mississippi Power Company 2009 Annual Report

Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	65,025		$	22,413
Receivables —
Customer accounts receivable		36,766			40,262
Unbilled revenues		27,168			24,798
Under recovered regulatory clause revenues		—			54,994
Other accounts and notes receivable		11,337			8,995
Affiliated companies		13,215			24,108
Accumulated provision for uncollectible accounts		(940	)		(1,039	)
Fossil fuel stock, at average cost		127,237			85,538
Materials and supplies, at average cost		27,793			27,143
Other regulatory assets, current		53,273			59,220
Prepaid income taxes		32,237			1,061
Other current assets		12,625			9,837
Total current assets		405,736			357,330
Property, Plant, and Equipment:
In service		2,316,494			2,234,573
Less accumulated provision for depreciation		950,373			923,269
Plant in service, net of depreciation		1,366,121			1,311,304
Construction work in progress		48,219			70,665
Total property, plant, and equipment		1,414,340			1,381,969
Other Property and Investments		7,018			8,280
Deferred Charges and Other Assets:
Deferred charges related to income taxes		8,536			9,566
Other regulatory assets, deferred		209,100			171,680
Other deferred charges and assets		27,951			23,870
Total deferred charges and other assets		245,587			205,116
Total Assets	$	2,072,681		$	1,952,695

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

II-341

BALANCE SHEETS
At December 31, 2009 and 2008
Mississippi Power Company 2009 Annual Report

Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,330	$	41,230
Notes payable		—		26,293
Accounts payable —
Affiliated		49,209		36,847
Other		38,662		63,704
Customer deposits		11,143		10,354
Accrued taxes —
Accrued income taxes		10,590		8,842
Other accrued taxes		49,547		50,700
Accrued interest		5,739		3,930
Accrued compensation		13,785		20,604
Other regulatory liabilities, current		7,610		9,718
Over recovered regulatory clause liabilities		48,596		—
Liabilities from risk management activities		19,454		29,291
Other current liabilities		21,142		19,144
Total current liabilities		276,807		320,657
Long-Term Debt(See accompanying statements)		493,480		370,460
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		223,066		222,324
Deferred credits related to income taxes		13,937		14,074
Accumulated deferred investment tax credits		12,825		14,014
Employee benefit obligations		161,778		142,188
Other cost of removal obligations		97,820		96,191
Other regulatory liabilities, deferred		54,576		51,340
Other deferred credits and liabilities		47,090		52,216
Total deferred credits and other liabilities		611,092		592,347
Total Liabilities		1,381,379		1,283,464
Redeemable Preferred Stock(See accompanying statements)		32,780		32,780
Common Stockholder’s Equity(See accompanying statements)		658,522		636,451
Total Liabilities and Stockholder’s Equity	$	2,072,681	$	1,952,695
Commitments and Contingent Matters(See notes)

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

II-342

STATEMENTS OF CAPITALIZATION
At December 31, 2009 and 2008
Mississippi Power Company 2009 Annual Report

	2009			2008			2009			2008
	(in thousands)						(percent of total)
Long-Term Debt:
Long-term notes payable —
6.00% due 2013		50,000			50,000
5.4% to 5.625% due 2017-2035		280,000			155,000
Adjustable rates (0.68% at 1/1/10) due 2011		80,000			120,000
Total long-term notes payable		410,000			325,000
Other long-term debt —
Pollution control revenue bonds:
5.15% due 2028		42,625			42,625
Variable rates (0.25% to 0.30% at 1/1/10) due 2020-2028		40,070			40,070
Total other long-term debt		82,695			82,695
Capitalized lease obligations		3,399			4,630
Unamortized debt discount		(1,284	)		(635	)
Total long-term debt (annual interest requirement — $21.6 million)		494,810			411,690
Less amount due within one year		1,330			41,230
Long-term debt excluding amount due within one year		493,480			370,460			41.6	%		35.6	%
Cumulative Redeemable 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			2.8			3.2
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		325,562			319,958
Retained earnings		295,269			278,802
Accumulated other comprehensive income (loss)		—			—
Total common stockholder’s equity		658,522			636,451			55.6			61.2
Total Capitalization	$	1,184,782		$	1,039,691			100.0	%		100.0	%

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

II-343

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2009, 2008, and 2007
Mississippi Power Company 2009 Annual Report

	Number of										Accumulated
	Common										Other
	Shares		Common		Paid-In			Retained			Comprehensive
	Issued		Stock		Capital			Earnings			Income (Loss)			Total
	(in thousands)
Balance at December 31, 2006		1,121	$	37,691	$	307,019		$	244,511		$	599		$	589,820
Net income after dividends on preferred stock		—		—		—			84,031			—			84,031
Capital contributions from parent company		—		—		7,333			—			—			7,333
Other comprehensive income (loss)		—		—		—			—			(26	)		(26	)
Cash dividends on common stock		—		—		—			(67,300	)		—			(67,300	)
Other		—		—		(28	)		—			—			(28	)
Balance at December 31, 2007		1,121		37,691		314,324			261,242			573			613,830
Net income after dividends on preferred stock		—		—		—			85,960			—			85,960
Capital contributions from parent company		—		—		5,634			—			—			5,634
Other comprehensive income (loss)		—		—		—			—			(573	)		(573	)
Cash dividends on common stock		—		—		—			(68,400	)		—			(68,400	)
Balance at December 31, 2008		1,121		37,691		319,958			278,802			—			636,451
Net income after dividends on preferred stock		—		—		—			84,967			—			84,967
Capital contributions from parent company		—		—		5,604			—			—			5,604
Other comprehensive income (loss)		—		—		—			—			—			—
Cash dividends on common stock		—		—		—			(68,500	)		—			(68,500	)
Balance at December 31, 2009		1,121	$	37,691	$	325,562		$	295,269		$	—		$	658,522

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

II-344

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Mississippi Power Company 2009 Annual Report

	2009		2008			2007
	(in thousands)
Net income after dividends on preferred stock	$	84,967	$	85,960		$	84,031
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(355), and $(16), respectively		—		(573	)		(26	)
Comprehensive Income	$	84,967	$	85,387		$	84,005

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

II-345

NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2009 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power), are vertically integrated utilities providing 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, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

The equity method is used for entities 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 the current year presentation.

The Company is subject to regulation by the Federal Energy Regulatory Commission (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, digital wireless communications, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $84 million, $87 million, and $71.8 million during 2009, 2008, and 2007, respectively. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. The Company provided no significant service to an affiliate in 2009, 2008, and 2007. The Company received storm restoration assistance from other Southern Company subsidiaries totaling $3.2 million in 2008. There was no storm assistance received in 2009 or 2007.

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 $10.2 million, $11.1 million, and $9.8 million in 2009, 2008, and 2007, 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 $20.9 million, $22.8 million, and $23.1 million in 2009, 2008, and 2007, respectively. See Note 4 for additional information.

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Mississippi Power Company 2009 Annual Report

The traditional 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 the Financial Accounting Standards Board in accounting for the effects of rate 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:

	2009			2008			Note
	(in thousands)
Hurricane Katrina	$	(143	)	$	(143	)		(a	)
Underfunded retiree benefit plans		99,690			87,094			(b,k	)
Property damage		(57,814	)		(54,241	)		(m	)
Deferred income tax charges		9,027			8,862			(d	)
Property tax		17,170			16,333			(e	)
Transmission & distribution deferral		4,734			7,101			(f	)
Vacation pay		8,756			8,498			(g,k	)
Loss on reacquired debt		8,409			9,133			(h	)
Loss on redeemed preferred stock		229			400			(i	)
Loss on rail cars		108			196			(h	)
Other regulatory assets		1,087			—			(c	)
Fuel-hedging (realized and unrealized) losses		44,116			56,516			(j,k	)
Asset retirement obligations		8,955			8,345			(d	)
Deferred income tax credits		(14,853	)		(14,962	)		(d	)
Other cost of removal obligations		(97,820	)		(96,191	)		(d	)
Fuel-hedging (realized and unrealized) gains		(551	)		(761	)		(j,k	)
Generation screening costs		68,496			37,857			(l	)
Other liabilities		(2,628	)		(4,894	)		(c	)
Total assets (liabilities), net	$	96,968		$	69,143

Note:	The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
(a)	For additional information, see Note 3 under “Retail Regulatory Matters — Storm Damage Cost Recovery.”
(b)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
(c)	Recorded and recovered as approved by the Mississippi PSC over periods not exceeding two years.
(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)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year.
(f)	Amortized over a four-year period ending 2011.
(g)	Recorded as earned by employees and recovered as paid, generally within one year.
(h)	Recovered over the remaining life of the original issue/lease or, if refinanced, over the life of the new issue/lease, which may range up to 50 years.
(i)	Amortized over a period beginning in 2004 that is not to exceed seven years.
(j)	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).
(k)	Not earning a return as offset by a corresponding asset or liability.
(l)	Recovery expected to be determined by the Mississippi PSC by May 1, 2010. For additional information, see Note 3 under “Retail Regulatory Matters — Integrated Coal Gasification Combined Cycle.”
(m)	For additional information, see Note 1 under “Provision for Property Damage” and Note 3 under “Retail Regulatory Matters — System Restoration Rider.”

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Mississippi Power Company 2009 Annual Report

In the event that a portion of the Company’s operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off or reclassify to accumulated other comprehensive income 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 values. All regulatory assets and liabilities are to be reflected in rates.

Government Grants

The Company received a grant in October 2006 from the Mississippi Development Authority (MDA) for $276.4 million, primarily for storm damage cost recovery. In 2007, the Company received $109.3 million of storm restoration bond proceeds under the state bond program of which $25.2 million was for retail storm restoration cost, $60.0 million was to increase the Company’s retail property damage reserve, and $24.1 million was to cover the retail portion of construction of a new storm operations center. In 2008, the Company received grant payments in the amount of $7.3 million and anticipates the receipt of approximately $3.2 million in 2010. The grant proceeds do not represent a future obligation of the Company. The portion of any grants received related to retail storm recovery was applied to the retail regulatory asset that was established as restoration costs were incurred. The portion related to wholesale storm recovery was recorded either as a reduction to operations and maintenance expense or as a reduction to total property, plant, and equipment depending on the restoration work performed and the appropriate allocations of cost of service.

Revenues

Energy and other revenues are recognized as services are provided. Wholesale 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 related to retail sales 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, 2009 and 2008, no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel hedging programs as approved by the Mississippi PSC.

Income and Other 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. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

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 for projects over $10 million.

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Mississippi Power Company 2009 Annual Report

The Company’s property, plant, and equipment consisted of the following at December 31:

	2009		2008
	(in thousands)
Generation	$	963,145	$	919,149
Transmission		449,452		436,280
Distribution		748,066		720,124
General		155,831		159,020
Total plant in service	$	2,316,494	$	2,234,573

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 3.3%, in 2009, 2008, and 2007. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost, together with the cost of removal, less salvage, is charged to the accumulated depreciation provision. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of facilities. On September 8, 2009 and September 9, 2009, the Company filed with the Mississippi PSC and the FERC, respectively, a depreciation study as of December 31, 2008. The FERC accepted this study on October 20, 2009.

In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2009, the Company had a balance of the deferred retail portion of $4.7 million with $2.3 million included in current assets as other regulatory assets and $2.4 million included in other regulatory assets, deferred.

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 (MWs) 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 over a four-year period. The amount amortized in 2007 was $5.7 million. The regulatory liability was fully amortized as of December 31, 2007.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset’s future retirement and are 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. 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 are reflected in the balance sheets as a regulatory liability.

The Company has retirement obligations related to various landfill sites, underground storage tanks, and asbestos removal. The Company also has 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 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.

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Mississippi Power Company 2009 Annual Report

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

	2009			2008
	(in thousands)
Balance, beginning of year	$	17,977		$	17,290
Liabilities incurred		378			—
Liabilities settled		(1,892	)		(55	)
Accretion		1,049			967
Cash flow revisions		(81	)		(225	)
Balance, end of year	$	17,431		$	17,977

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 asset and recording a loss for the amount if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

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 regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. A 1999 Mississippi PSC order allowed the Company to accrue $1.5 million to $4.6 million to the reserve annually, with a maximum reserve totaling $23 million. In October 2006, in conjunction with the Mississippi PSC Hurricane Katrina-related financing order, the Mississippi PSC ordered the Company to cease all accruals to the retail property damage reserve until a new reserve cap is established. However, in the same financing order, the Mississippi PSC approved the replenishment of the retail property damage reserve with $60 million to be funded with a portion of the proceeds of bonds to be issued by the Mississippi Development Bank on behalf of the State of Mississippi and reported as liabilities by the State of Mississippi. The Company received the $60 million bond proceeds in June 2007. The Company made no discretionary retail accruals in 2008 and 2007 as a result of the order. On January 9, 2009, the Mississippi PSC approved the System Restoration Rider (SRR) stipulation between the Company and the Mississippi Public Utilities Staff. In accordance with the stipulation, every three years the Mississippi PSC, Mississippi Public Utilities Staff, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deem the change appropriate. Each year the Company will set rates to collect the approved SRR revenues. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In 2009, the Company made retail accruals of $3.7 million per the SRR order. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. See Note 3 under “Retail Regulatory Matters — Storm Damage Cost Recovery” and “Retail Regulatory Matters — System Restoration Rider” 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 have and/or may be approved by the Mississippi PSC to recover the deferred costs and accrue reserves. The Company accrued $0.3 million in 2009 and $0.2 million annually in 2008 and 2007 for the wholesale jurisdiction. See Note 3 under “FERC Matters — Wholesale Rate Filing” for additional information.

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Mississippi Power Company 2009 Annual Report

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances. Fuel is charged to inventory when purchased and then expensed as used and recovered by the Company through fuel cost recovery rates approved by the Mississippi PSC. Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in the prices of certain fuel purchases and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 9 for additional information. 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, 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. See Note 10 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2009.

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.

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 reclassifications for amounts included in net income.

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Mississippi Power Company 2009 Annual Report

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). No contributions to the plan are expected for the year ending December 31, 2010. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds trusts to the extent required by the FERC. For the year ending December 31, 2010, postretirement trust contributions are expected to total approximately $0.2 million.

The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to accounting standards related to defined postretirement benefit plans, the Company was required to change the measurement date for its defined postretirement benefit plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, the Company adopted the measurement date provisions effective January 1, 2008, resulting in an increase in long-term liabilities of $1.6 million and a decrease in prepaid pension costs of approximately $0.1 million.

Pension Plans

The total accumulated benefit obligation for the pension plans was $289 million in 2009 and $252 million in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as follows:

	2009			2008
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	266,879		$	256,903
Service cost		6,792			8,557
Interest cost		17,577			19,753
Benefits paid		(11,965	)		(14,721	)
Actuarial loss (gain)		29,896			(3,613	)
Balance at end of year		309,179			266,879
Change in plan assets
Fair value of plan assets at beginning of year		198,510			300,866
Actual return (loss) on plan assets		30,088			(89,420	)
Employer contributions		1,382			1,785
Benefits paid		(11,965	)		(14,721	)
Fair value of plan assets at end of year		218,015			198,510
Accrued liability	$	(91,164	)	$	(68,369	)

At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension plans were $285.9 million and $23.3 million, respectively. All pension plan assets are related to the qualified pension 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). In 2009, in determining the optimal asset allocation for the pension fund, the Company performed an extensive study based on projections of both assets and liabilities over a 10-year forward horizon. The primary goal of the study was to maximize plan funded status. The Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

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Mississippi Power Company 2009 Annual Report

The actual composition of the Company’s pension plan assets as of December 31, 2009 and 2008, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		29	%		33	%		34	%
International equity		28			29			23
Fixed income		15			15			14
Special situations		3			—			—
Real estate investments		15			13			19
Private equity		10			10			10
Total		100	%		100	%		100	%

The investment strategy for plan assets related to the Company’s defined benefit plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is actively managed through an allocation to long-dated, investment grade corporate and government bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

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Mississippi Power Company 2009 Annual Report

The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable
	Assets			Inputs			Inputs
As of December 31, 2009:	(Level 1)			(Level 2)			(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	43,279		$	17,897		$	—	$	61,176
International equity*		55,948			5,575			—		61,523
Fixed income:
U.S. Treasury, government, and agency bonds		—			16,118			—		16,118
Mortgage- and asset-backed securities		—			4,382			—		4,382
Corporate bonds		—			10,803			—		10,803
Pooled funds		—			390			—		390
Cash equivalents and other		108			13,211			—		13,319
Special situations		—			—			—		—
Real estate investments		6,747			—			21,195		27,942
Private equity		—			—			21,498		21,498
Total	$	106,082		$	68,376		$	42,693	$	217,151
Liabilities:
Derivatives		(172	)		(43	)		—		(215	)
Total	$	105,910		$	68,333		$	42,693	$	216,936

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	40,886		$	16,650	$	—	$	57,536
International equity*		36,783			3,382		—		40,165
Fixed income:
U.S. Treasury, government, and agency bonds		—			17,191		—		17,191
Mortgage- and asset-backed securities		—			8,145		—		8,145
Corporate bonds		—			11,147		—		11,147
Pooled funds		—			120		—		120
Cash equivalents and other		861			7,865		—		8,726
Special situations		—			—		—		—
Real estate investments		5,604			—		32,700		38,304
Private equity		—			—		19,092		19,092
Total	$	84,134		$	64,500	$	51,792	$	200,426
Liabilities:
Derivatives		(301	)		—		—		(301	)
Total	$	83,833		$	64,500	$	51,792	$	200,125

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in thousands)
Beginning balance	$	32,700		$	19,092	$	40,755		$	20,280
Actual return on investments:
Related to investments held at year end		(9,492	)		1,322		(6,651	)		(5,517	)
Related to investments sold during the year		(2,516	)		387		156			975
Total return on investments		(12,008	)		1,709		(6,495	)		(4,542	)
Purchases, sales, and settlements		503			697		(1,560	)		3,354
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	21,195		$	21,498	$	32,700		$	19,092

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s pension plan consist of the following:

	2009			2008
	(in thousands)
Other regulatory assets, deferred	$	85,357		$	66,602
Other current liabilities		(1,484	)		(1,498	)
Employee benefit obligations		(89,680	)		(66,871	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2010.

	Prior Service Cost		Net (Gain) Loss
	(in thousands)
Balance at December 31, 2009:
Regulatory assets	$	9,222	$	76,135
Balance at December 31, 2008:
Regulatory assets	$	10,800	$	55,802
Estimated amortization in net periodic pension cost in 2010:
Regulatory assets	$	1,391	$	634

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Mississippi Power Company 2009 Annual Report

The changes in the balances of regulatory assets and regulatory liabilities related to the defined benefit pension plans for the year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory			Regulatory
	Assets			Liabilities
	(in thousands)
Balance at December 31, 2007	$	11,114		$	(53,396	)
Net loss (gain)		56,721			54,849
Change in prior service costs/transition obligation		—			—
Reclassification adjustments:
Amortization of prior service costs		(489	)		(1,596	)
Amortization of net gain		(744	)		143
Total reclassification adjustments		(1,233	)		(1,453	)
Total change		55,488			53,396
Balance at December 31, 2008	$	66,602		$	—
Net loss (gain)		20,872			—
Change in prior service costs/transition obligation		—			—
Reclassification adjustments:
Amortization of prior service costs		(1,578	)		—
Amortization of net gain		(539	)		—
Total reclassification adjustments		(2,117	)		—
Total change		18,755			—
Balance at December 31, 2009	$	85,357		$	—

Components of net periodic pension cost (income) were as follows:

	2009			2008			2007
	(in thousands)
Service cost	$	6,792		$	6,846		$	6,934
Interest cost		17,577			15,802			14,767
Expected return on plan assets		(21,065	)		(20,611	)		(19,099	)
Recognized net loss		539			481			634
Net amortization		1,578			1,668			1,591
Net periodic pension cost (income)	$	5,421		$	4,186		$	4,827

Net periodic pension cost (income) is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

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, 2009, estimated benefit payments were as follows:

	Benefit
	Payments
	(in thousands)
2010	$	13,509
2011		14,349
2012		15,373
2013		16,495
2014		18,078
2015 to 2019		108,602

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Mississippi Power Company 2009 Annual Report

Other Postretirement Benefits

Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31, 2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:

	2009			2008
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	84,733		$	84,495
Service cost		1,328			1,745
Interest cost		5,535			6,498
Benefits paid		(4,041	)		(5,333	)
Actuarial gain		(1,550	)		(3,275	)
Plan amendments		(2,592	)		—
Retiree drug subsidy		361			603
Balance at end of year		83,774			84,733
Change in plan assets
Fair value of plan assets at beginning of year		18,623			25,593
Actual return (loss) on plan assets		2,902			(5,653	)
Employer contributions		2,447			3,414
Benefits paid		(3,680	)		(4,731	)
Fair value of plan assets at end of year		20,292			18,623
Accrued liability	$	(63,482	)	$	(66,110	)

Other postretirement benefit 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. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. The actual composition of the Company’s other postretirement benefit plan assets as of the end of year, along with the targeted mix of assets, is presented below:

	Target			2009			2008
Domestic equity		22	%		26	%		26	%
International equity		22			22			18
Fixed income		34			34			35
Special situations		2			—			—
Real estate investments		12			10			14
Private equity		8			8			7
Total		100	%		100	%		100	%

Detailed below is a description of the investment strategies for each major asset category disclosed above:

• Domestic equity.This portion of the portfolio comprises a mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes managed both actively and through passive index approaches.

• International equity.This portion of the portfolio is actively managed with a blend of growth stocks and value stocks with both developed and emerging market exposure.

• Fixed income.This portion of the portfolio is comprised of domestic bonds.

• Special situations.Though currently unfunded, this portion of the portfolio was established both to execute opportunistic investment strategies with the objectives of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising new strategies of a longer-term nature.

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Mississippi Power Company 2009 Annual Report

• Trust-owned life insurance.Some of the Company’s taxable trusts invest in these investments in order to minimize the impact of taxes on the portfolio.

• Real estate investments.Assets in this portion of the portfolio are invested in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

• Private equity.This portion of the portfolio generally consists of investments in private partnerships that invest in private or public securities typically through privately negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed debt are examples of investment strategies within this category.

The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable
	Assets			Inputs			Inputs
As of December 31, 2009:	(Level 1)			(Level 2)			(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	3,011		$	1,245		$	—	$	4,256
International equity*		3,893			387			—		4,280
Fixed income:
U.S. Treasury, government, and agency bonds		—			5,155			—		5,155
Mortgage- and asset-backed securities		—			304			—		304
Corporate bonds		—			751			—		751
Pooled funds		—			27			—		27
Cash equivalents and other		8			1,295			—		1,303
Trust-owned life insurance		—			—			—		—
Special situations		—			—			—		—
Real estate investments		468			—			1,475		1,943
Private equity		—			—			1,497		1,497
Total	$	7,380		$	9,164		$	2,972	$	19,516
Liabilities:
Derivatives		(12	)		(3	)		—		(15	)
Total	$	7,368		$	9,161		$	2,972	$	19,501

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

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Mississippi Power Company 2009 Annual Report

	Fair Value Measurements Using
	Quoted Prices
	in Active			Significant
	Markets for			Other		Significant
	Identical			Observable		Unobservable
	Assets			Inputs		Inputs
As of December 31, 2008:	(Level 1)			(Level 2)		(Level 3)		Total
	(in thousands)
Assets:
Domestic equity*	$	2,857		$	1,164	$	—	$	4,021
International equity*		2,571			238		—		2,809
Fixed income:
U.S. Treasury, government, and agency bonds		—			5,558		—		5,558
Mortgage- and asset-backed securities		—			570		—		570
Corporate bonds		—			779		—		779
Pooled funds		—			9		—		9
Cash equivalents and other		59			888		—		947
Trust-owned life insurance		—			—		—		—
Special situations		—			—		—		—
Real estate investments		391			—		2,287		2,678
Private equity		—			—		1,335		1,335
Total	$	5,878		$	9,206	$	3,622	$	18,706
Liabilities:
Derivatives		(22	)		—		—		(22	)
Total	$	5,856		$	9,206	$	3,622	$	18,684

* Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as follows:

	2009					2008
	Real Estate					Real Estate
	Investments			Private Equity		Investments			Private Equity
	(in thousands)
Beginning balance	$	2,287		$	1,335	$	2,755		$	1,371
Actual return on investments:
Related to investments held at year end		(676	)		87		(372	)		(328	)
Related to investments sold during the year		(171	)		28		10			65
Total return on investments		(847	)		115		(362	)		(263	)
Purchases, sales, and settlements		35			47		(106	)		227
Transfers into/out of Level 3		—			—		—			—
Ending balance	$	1,475		$	1,497	$	2,287		$	1,335

The fair values presented above are prepared in accordance with applicable accounting standards regarding fair value. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Securities for which the activity is observable on an active market or traded exchange are categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix pricing, a common model using observable inputs. Domestic and international equity securities classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but where the value is determined using observable inputs from the market. Securities that are valued using unobservable inputs are classified as Level 3 and include investments in real estate and investments in limited partnerships. The Company invests (through the pension plan trustee) directly in the limited partnerships which then invest in various types of funds or various private entities within a fund. The fair value

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Mississippi Power Company 2009 Annual Report

of the limited partnerships’ investments is based on audited annual capital accounts statements which are generally prepared on a fair value basis. The Company also relies on the fact that, in most instances, the underlying assets held by the limited partnerships are reported at fair value. External investment managers typically send valuations to both the custodian and to the Company within 90 days of quarter end. The custodian reports the most recent value available and adjusts the value for cash flows since the statement date for each respective fund.

Amounts recognized in the balance sheets related to the Company’s other postretirement benefit plans consist of the following:

	2009			2008
	(in thousands)
Other regulatory assets, deferred	$	14,332		$	20,491
Employee benefit obligations		(63,482	)		(66,110	)

Presented below are the amounts included in regulatory assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not yet been recognized in net periodic postretirement benefit cost along with the estimated amortization of such amounts for 2010.

	Prior Service			Net (Gain)		Transition
	Cost			Loss		Obligation
	(in thousands)
Balance at December 31, 2009:
Regulatory assets	$	(1,107	)	$	14,811	$	628
Balance at December 31, 2008:
Regulatory assets	$	1,054		$	18,020	$	1,417
Estimated amortization as net periodic postretirement benefit cost in 2010:
Regulatory assets	$	(57	)	$	403	$	228

The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan year ended December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:

	Regulatory
	Assets
	(in thousands)
Balance at December 31, 2007	$	17,217
Net loss		4,607
Change in prior service costs/transition obligation		—
Reclassification adjustments:
Amortization of transition obligation		(433	)
Amortization of prior service costs		(132	)
Amortization of net gain		(768	)
Total reclassification adjustments		(1,333	)
Total change		3,274
Balance at December 31, 2008	$	20,491
Net gain		(2,648	)
Change in prior service costs/transition obligation		(2,592	)
Reclassification adjustments:
Amortization of transition obligation		(307	)
Amortization of prior service costs		(51	)
Amortization of net gain		(561	)
Total reclassification adjustments		(919	)
Total change		(6,159	)
Balance at December 31, 2009	$	14,332

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Mississippi Power Company 2009 Annual Report

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

	2009			2008			2007
	(in thousands)
Service cost	$	1,328		$	1,396		$	1,372
Interest cost		5,535			5,199			5,254
Expected return on plan assets		(1,783	)		(1,805	)		(1,673	)
Net amortization		919			1,066			1,633
Net postretirement cost	$	5,999		$	5,856		$	6,586

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced the Company’s expenses for the years ended December 31, 2009, 2008, and 2007 by approximately $1.7 million, $1.8 million, and $1.8 million, respectively.

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 Payments		Subsidy Receipts			Total
	(in thousands)
2010	$	4,731	$	(520	)	$	4,211
2011		5,157		(583	)		4,574
2012		5,520		(663	)		4,857
2013		5,943		(730	)		5,213
2014		6,217		(821	)		5,396
2015 to 2019		35,141		(5,395	)		29,746

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual salary increase of 3.50%.

	2009			2008			2007
Discount rate:
Pension plans		5.92	%		6.75	%		6.30	%
Other postretirement benefit plans		5.83			6.75			6.30
Annual salary increase		4.18			3.75			3.75
Long-term return on plan assets:
Pension plans		8.50			8.50			8.50
Other postretirement benefit plans		7.62			7.85			7.77

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust’s target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust’s asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust’s portfolio.

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Mississippi Power Company 2009 Annual Report

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2009 as follows:

	1 Percent		1 Percent
	Increase		Decrease
	(in thousands)
Benefit obligation	$	5,025	$	4,571
Service and interest costs		398		404

Employee Savings Plan

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $3.9 million, $3.7 million, and $3.5 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company’s business activities are subject to extensive governmental regulation related to public health and the environment such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. These actions were filed concurrently with the issuance of notices of violations to the Company with respect to the Company’s Plant Watson. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by the Company. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. In early 2000, the EPA filed a motion to amend its complaint to add the Company as a defendant based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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 $37,500 per day, per violation at each

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Mississippi Power Company 2009 Annual Report

generating unit, depending on the date of the alleged violation. An adverse outcome in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. 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. The 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 in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. On November 5, 2009, the defendants, including Southern Company, sought rehearing en banc, and the court’s ruling is subject to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter 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 releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up

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Mississippi Power Company 2009 Annual Report

properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms.

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 2007, 2008, and 2009 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 impact of this matter on the Company will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by the Company are expected to be recovered through the Environmental Compliance Overview (ECO) Plan.

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, the Company does not believe that additional liabilities, 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, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by the Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that the Company possesses or has exercised any market power. The agreement likewise does not require the Company to make any refunds related to sales during the 15-month refund period. Under the agreement, the Company will donate $0.1 million to nonprofit organizations in the State of Mississippi for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies (including the Company), Southern Power, and Southern Company Services, Inc., as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

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Mississippi Power Company 2009 Annual Report

Wholesale Rate Filing

In August 2008, the Company filed with the FERC a request for revised wholesale electric tariff and rates. Prior to making this filing, the Company reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provided for an increase in annual base wholesale revenues in the amount of $5.8 million, effective January 1, 2009. In addition, the settlement agreement allows the Company to increase its annual accrual for the wholesale portion of property damage to $303,000 per year, to defer any property damage costs prudently incurred in excess of the wholesale property damage reserve balance, and to defer the wholesale portion of the generation screening and evaluation costs associated with the integrated coal gasification combined cycle (IGCC) project to be located in Kemper County Mississippi. The settlement agreement also provided that the Company will not seek a change in wholesale full-requirements rates before November 1, 2010, except for changes associated with the fuel adjustment clause and the ECM, changes associated with property damages that exceed the amount in the wholesale property damage reserve, and changes associated with costs and expenses associated with environmental requirements affecting fossil fuel generating facilities. In October 2008, the Company received notice that the FERC had accepted the filing effective November 1, 2008, and the revised monthly charges were applied beginning January 1, 2009. As result of the order, the Company reclassified $9.3 million of previously expensed generation screening and evaluation costs to a regulatory asset. See “Integrated Coal Gasification Combined Cycle” herein for additional information.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including the Company, 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 the Company believes that it has complied with applicable laws and that the plaintiffs’ claims are without merit.

To date, the Company has entered into agreements with plaintiffs in approximately 95% 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 the related cases have been dismissed. These agreements have not resulted in any material effects on the Company’s financial statements.

In addition, in late 2001, certain subsidiaries of Southern Company, including the Company, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fibernet, Inc., a subsidiary of telecommunications company ITC DeltaCom, Inc. 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 the 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 the PEP and to reclassify to jurisdictional cost of service the 266 MWs 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 amortized the regulatory liability pursuant to the

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Mississippi PSC’s order, over a four-year period, resulting in increases to earnings in each of those years. The final amortization of $5.7 million occurred in 2007.

In addition, in May 2004, the Mississippi PSC 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 are limited to 4% of retail revenues annually under the revised PEP. PEP will remain in effect until the Mississippi PSC modifies, suspends, or terminates the plan. In the May 2004 order, the Mississippi PSC ordered that the Mississippi Public Utilities Staff and the Company review the operations of the PEP in 2007. By mutual agreement, this review was deferred until 2008 and continued into 2009. On March 2, 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. On August 3, 2009, the Mississippi Public Utilities Staff and the Company filed a joint report with the Mississippi PSC proposing several changes to the PEP. On November 9, 2009, the Mississippi PSC approved the revised PEP, which resulted in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. On November 16, 2009, the Company resumed annual evaluations and filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change.

In April 2007, the Mississippi PSC issued an order allowing the Company to defer certain reliability-related maintenance costs beginning January 1, 2007 and recover them evenly over a four-year period beginning January 1, 2008. These costs related to maintenance that was needed as follow-up to emergency repairs that were made subsequent to Hurricane Katrina. At December 31, 2007, the Company had incurred and deferred the retail portion of $9.5 million of such costs. At December 31, 2009, the Company had a balance of the deferred retail portion of $4.7 million with $2.3 million included in current assets as other regulatory assets and $2.4 million included in long-term other regulatory assets.

In September 2007, the Mississippi Public Utilities Staff and the Company entered into a stipulation that included adjustments to expenses which resulted in a one-time credit to retail customers of approximately $1.1 million. In November 2007, the Mississippi PSC issued an order requiring the Company to refund this amount to its retail customers no later than December 2007. This amount was totally refunded as a credit to customer bills by December 31, 2007.

In December 2007, the Company submitted its annual PEP filing for 2008, which resulted in a rate increase of 1.983% or $15.5 million annually, effective January 2008. In December 2006, the Company submitted its annual PEP filing for 2007, which resulted in no rate change.

In December 2007, the Company received an order from the Mississippi PSC requiring it to defer $1.4 million associated with the retail portion of certain tax credits and adjustments related to permanent differences pertaining to its 2006 income tax returns filed in September 2007. These tax differences were recorded in a regulatory liability included in the current portion of other regulatory liabilities and were amortized ratably over the 12-month period beginning January 2008. The amortization of $1.4 million is included in income taxes on the statement of income for 2008.

On March 16, 2009, the Company submitted its annual PEP lookback filing for 2008, which recommended no surcharge or refund. At the conclusion of the Mississippi Public Utilities Staff’s review of the PEP lookback filing for 2008, the Company and Mississippi Public Utilities Staff jointly submitted a stipulation to the Mississippi PSC which recommended no surcharge or refund.

System Restoration Rider

In September 2006, the Company filed with the Mississippi PSC a request to implement a SRR to increase the Company’s cap on the property damage reserve and to authorize the calculation of an annual property damage accrual based on a formula. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self insurance) and to facilitate the Mississippi PSC’s review of these costs. The Company would be required to make annual SRR filings to determine the revenue requirement associated with the property damage. In November 2007, the Company along with the Mississippi Public Utilities Staff agreed and stipulated to a revised SRR calculation method that would no longer require the Mississippi PSC to set a cap on the property damage reserve or to authorize the calculation of an annual property damage accrual. Under the revised SRR calculation method, the Mississippi PSC would periodically agree on SRR revenue levels that would be developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information.

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Mississippi Power Company 2009 Annual Report

On January 9, 2009, the Mississippi PSC issued an order accepting the stipulation and the revised SRR calculation method. The applicable SRR rate level will be adjusted every three years, unless a significant change in circumstances occurs such that the Company and the Mississippi Public Utilities Staff or the Mississippi PSC deems that a more frequent change would be appropriate. The Company will submit annual filings setting forth SRR-related revenues, expenses, and investment for the projected filing period, as well as the true-up for the prior period. As a result, the December 2008 retail regulatory liability of $6.8 million was reclassified to the property damage reserve. On February 2, 2009, the Company submitted its 2009 SRR rate filing with the Mississippi PSC, which proposed that the 2009 SRR rate level remain at zero and the Company be allowed to accrue approximately $4.0 million to the property damage reserve in 2009. On September 10, 2009, the Mississippi PSC issued an order requiring the Company to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million from November 2009 to March 2010 under the new rate. On January 29, 2010, the Company submitted its 2010 SRR rate filing with the Mississippi PSC, which proposed that the Company be allowed to accrue approximately $3.0 million to the property damage reserve in 2010. The final outcome of this matter cannot now be determined.

Environmental Compliance Overview Plan

On February 12, 2010, the Company submitted its 2010 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $3.9 million. In its 2010 ECO filing, the Company is proposing to change the true-up provision of the ECO rate schedule to consider actual revenues collected in addition to actual costs. The final outcome of this matter cannot now be determined. On February 3, 2009, the Company submitted its 2009 ECO Plan notice which proposed an increase in annual revenues for the Company of approximately $1.5 million. On June 19, 2009, the Mississippi PSC approved the ECO Plan with the new rates effective June 2009. In February 2008, the Company filed with the Mississippi PSC its annual ECO Plan evaluation for 2008. After the filing of the ECO Plan evaluation in February 2008, the regulations addressing mercury emissions were altered by a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in February 2008. In April 2008, the Company filed with the Mississippi PSC a supplemental ECO Plan evaluation in which the projects included in the ECO Plan evaluation in February 2008 being undertaken primarily for mercury control were removed. In this supplemental ECO Plan filing, the Company requested a 15 cent per 1,000 kilowatt-hour decrease for retail residential customers. The Mississippi PSC approved the supplemental ECO Plan evaluation in June 2008, with the new rates effective in June 2008.

Fuel Cost Recovery

The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred on November 16, 2009. The Mississippi PSC approved the retail fuel cost recovery factor on December 15, 2009, with the new rates effective in January 2010. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 11.3% of total 2009 retail revenue. At December 31, 2009, the amount of over recovered retail fuel cost included in the balance sheets was $29.4 million compared to $36.0 million under recovered at December 31, 2008. The Company also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2010, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 20.9% of total 2009 MRA revenue. Effective February 1, 2010, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 16.9% of total 2009 MB revenue. At December 31, 2009, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $16.8 million and $2.4 million compared to $15.4 million and $3.7 million, respectively, under recovered at December 31, 2008. 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 decrease to the billing factor will have no significant effect on the Company’s revenues or net income, but will decrease annual cash flow.

In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi including the Company. On March 4, 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. On May 20, 2009, the Company filed the carrying cost calculation methodology as part of its compliance filing.

In August 2009, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company’s fuel-related expenditures included in the fuel adjustment clause and energy cost management clause of 2008 and 2009. The audit was completed in December 2009. There were no audit findings identified in the audit.

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Mississippi Power Company 2009 Annual Report

Storm Damage Cost Recovery

In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within the Company’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million, was affirmed by the Mississippi PSC in June 2006, and the Company was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing the Company to file an application with the MDA for a Community Development Block Grant (CDBG). In October 2006, the Company received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. These funds were received in June 2007. The Company affirmed the $302.4 million total storm costs incurred as of December 31, 2007. On March 2, 2009, the Company filed with the Mississippi PSC its final accounting of the restoration cost relating to Hurricane Katrina and the storm operations center. The final net retail receivable of approximately $3.2 million is expected to be recovered in 2010.

Integrated Coal Gasification Combined Cycle

On January 16, 2009, the Company filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. The plant would utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize the Company to acquire, construct, and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, the Company has requested certain rate recovery treatment in accordance with the State of Mississippi Baseload Act of 2008.

The Company filed an application in June 2006 with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the Kemper IGCC, and in November 2006 the Internal Revenue Service (IRS) allocated Internal Revenue Code Section 48A tax credits of $133 million to the Company. On May 11, 2009, the Company received notification from the IRS formally certifying these tax credits. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014. The Company has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for the Section 48A credits.

In February 2008, the Company also requested that the DOE transfer the remaining funds previously granted to a cancelled Southern Company project that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds to the Kemper IGCC. The estimated construction cost of the Kemper IGCC is approximately $2.4 billion, which is net of $245 million related to funding to be received from the DOE related to project construction. The remaining DOE funding of $25 million is projected to be used for demonstration over the first few years of operation.

On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. The Company expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law.

Beginning in December 2006, the Mississippi PSC has approved the Company’s requested accounting treatment to defer the costs associated with the Company’s generation resource planning, evaluation, and screening activities as a regulatory asset. In December 2008, the Company requested an amendment to its original order that would allow these costs to continue to be charged to and remain in a regulatory asset until January 1, 2010. On April 6, 2009, the Company received an accounting order from the Mississippi PSC directing the Company to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of the Company’s prudent expenditures. The Mississippi PSC’s determination of prudence for the Company’s pre-construction costs is scheduled to occur by May 2010. As of December 31, 2009, the Company had spent a total of $73.5 million associated with the Company’s

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Mississippi Power Company 2009 Annual Report

generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the year ended December 31, 2009 totaled $31.2 million as compared to $24.2 million for the year ended December 31, 2008. Of the total $73.5 million, $68.5 million was deferred in other regulatory assets, $4.0 million was related to land purchases capitalized, and $1.0 million was expensed.

On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. On August 4, 2009, the Mississippi PSC ordered a two-part hearing process to evaluate the need for and the resources and cost of the new generating capacity separately. On November 9, 2009, the Mississippi PSC issued an order that found the Company has a demonstrated need for additional capacity of approximately 304 MWs to 1,276 MWs based on an analysis of expected load forecasts, costs, and anticipated retirements. Hearings related to the appropriate resource to meet that need as well as cost recovery of that resource through application of the State of Mississippi’s Baseload Act of 2008 were held in February 2010. A decision on the resources and cost recovery is expected to be made by May 1, 2010.

On September 15, 2009, South Mississippi Electric Power Association (SMEPA) signed a non-binding letter of intent to explore the acquisition of an interest in the Kemper IGCC. The Company and SMEPA are evaluating a combination of a joint ownership arrangement and a power purchase agreement which would provide SMEPA with up to 20% of the capacity and associated energy output from the Kemper IGCC.

The final outcome of this matter cannot now be determined.

4. JOINT OWNERSHIP AGREEMENTS

The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company.

At December 31, 2009, 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		40	%	$	85,498	$	42,068
Units 1 and 2
Daniel		50	%	$	274,415	$	139,608
Units 1 and 2

The Company’s proportionate share of plant operating expenses is included in the statements of income and the Company is responsible for its own financing.

5. INCOME TAXES

Southern Company files 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 it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

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Mississippi Power Company 2009 Annual Report

Current and Deferred Income Taxes

Details of the income tax provisions were as follows:

	2009			2008		2007
	(in thousands)
Federal —
Current	$	77,619		$	20,834	$	79,127
Deferred		(32,980	)		22,054		(34,524	)
		44,639			42,888		44,603
State —
Current		12,444			2,675		9,274
Deferred		(6,869	)		2,786		(2,047	)
		5,575			5,461		7,227
Total	$	50,214		$	48,349	$	51,830

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:

	2009		2008
	(in thousands)
Deferred tax liabilities —
Accelerated depreciation	$	279,683	$	261,091
Basis differences		19,730		29,089
Fuel clause under recovered		—		25,534
Energy cost management clause under recovered		25,232		—
Regulatory assets associated with asset retirement obligations		6,876		7,100
Regulatory assets associated with employee benefit obligations		43,535		37,003
Other		21,679		20,915
Total		396,735		380,732
Deferred tax assets —
Federal effect of state deferred taxes		8,979		10,724
Fuel clause over recovered		44,009		—
Energy cost management clause over recovered		—		2,264
Other property basis differences		7,367		7,338
Pension and other benefits		64,553		56,024
Property insurance		22,365		21,997
Unbilled fuel		12,194		10,400
Long-term service agreement		21,317		16,595
Asset retirement obligations		6,876		7,100
Other		18,246		17,758
Total		205,906		150,200
Total deferred tax liabilities, net		190,829		230,532
Portion included in (accrued) prepaid income taxes, net		32,237		(8,208	)
Accumulated deferred income taxes	$	223,066	$	222,324

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Mississippi Power Company 2009 Annual Report

At December 31, 2009, the tax-related regulatory assets and liabilities were $9.0 million and $14.9 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.

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, $1.2 million, and $1.1 million for 2009, 2008, and 2007, respectively. At December 31, 2009, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

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:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		2.7			2.6			3.0
Non-deductible book depreciation		0.3			0.3			0.3
Production activities deduction		(1.1	)		(0.4	)		(0.5	)
Medicare subsidy		(0.4	)		(0.5	)		(0.5	)
Amortization of permanent tax items(a)		0.0			(0.7	)		—
Other		0.2			(0.8	)		0.4
Effective income tax rate		36.7	%		35.5	%		37.7	%

^(a) Amortization of Regulatory Liability Tax Credits. See Note 3 under “Retail Regulatory Matters — Performance Evaluation Plan.”

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, the Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits increased by $1.2 million, resulting in a balance of $3.0 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009			2008			2007
	(in thousands)
Unrecognized tax benefits at beginning of year	$	1,772		$	935		$	656
Tax positions from current periods		1,309			653			177
Tax positions from prior periods		(55	)		265			102
Reductions due to settlements		—			(81	)		—
Reductions due to expired statute of limitations		—			—			—
Balance at end of year	$	3,026		$	1,772		$	935

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Mississippi Power Company 2009 Annual Report

The tax positions from current periods increase for 2009 relate primarily to the production activities deduction tax position and other miscellaneous uncertain tax positions. The tax positions increase from prior periods for 2009 relates primarily to the production activities deduction tax position. See “Effective Tax Rate” above for additional information.

Impact on the Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
	(in thousands)
Tax positions impacting the effective tax rate	$	3,026	$	1,772	$	935
Tax positions not impacting the effective tax rate		—		—		—
Balance of unrecognized tax benefits	$	3,026	$	1,772	$	935

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008			2007
	(in thousands)
Interest accrued at beginning of year	$	203	$	106		$	37
Interest reclassified due to settlements		—		(17	)		—
Interest accrued during the year		27		114			69
Balance at end of year	$	230	$	203		$	106

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of the Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The possible conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

6. FINANCING

Bank Term Loans

In 2008, the Company borrowed $80 million under a three-year term loan agreement. The proceeds were used for general corporate purposes, including the Company’s continuous construction program.

Senior Notes

In March 2009, the Company issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. Proceeds were used to repay at maturity the Company’s $40.0 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of its short-term indebtedness and for general corporate purposes, including the Company’s continuous construction program. In November 2008, the Company issued $50.0 million of Series 2008A 6.00% Senior Notes due November 15, 2013. At December 31, 2009 and 2008, the Company had a total of $330 million and $245 million, respectively, of senior notes outstanding.

Securities Due Within One Year

At December 31, 2009 and 2008, the Company has scheduled maturities of capital leases due within one year of $1.3 million and $1.2 million, respectively. At December 31, 2008, the Company also had senior notes of $40.0 million due within one year.

Maturities through 2013 applicable to total long-term debt are as follows: $1.3 million in 2010; $81.4 million in 2011; $0.6 million in 2012; and $50.0 million in 2013. There are no scheduled maturities in 2014.

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Pollution Control Revenue 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, 2009 and 2008 was $82.7 million. In September 2008, the Company was required to purchase a total of approximately $7.9 million of variable rate pollution control revenue bonds that were tendered by investors. In December 2008, the bonds were successfully remarketed. On the statement of cash flow for 2008, the $7.9 million is presented as proceeds and redemptions.

Outstanding Classes of Capital Stock

The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as “Cumulative Redeemable Preferred Stock” in a manner consistent with temporary equity under applicable accounting standards. The Company’s preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company’s common stock with respect to payment of dividends and voluntary or involuntary dissolution. Certain series of the preferred stock and depositary preferred stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the stock.

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

Bank Credit Arrangements

At the beginning of 2010, the Company had total unused committed credit agreements with banks of $156 million, all of which expire in 2010. Approximately $41 million of the facilities contain two-year term loan options and $15 million contain one-year term loan options. The Company expects to renew its credit facilities, as needed, prior to expiration.

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 average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.

The credit arrangements contain covenants that limit the ratio of indebtedness to capitalization (each as defined in the arrangements) to 65%. For purposes of these definitions, indebtedness excludes long-term debt payable to affiliated trusts and, in certain cases, other hybrid securities.

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, 2009, the Company was in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowing.

This $156 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2009, the Company had no commercial paper outstanding. The credit arrangements also provide support to the Company’s variable rate tax-exempt pollution control bonds totaling $40.1 million. During 2009, the peak amount outstanding for short-term debt was $66.7 million and the average amount outstanding was $15.9 million. The average annual interest rate on short-term debt was 0.3% for 2009 and 2.6% for 2008.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $472 million in 2010, $661 million in 2011, and $1.3 billion in 2012. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; revised load growth

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estimates; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2009, significant purchase commitments were outstanding in connection with the construction program. 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 cover all planned inspections on the covered equipment, which generally 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 limits and scope specified in the LTSA.

In general, the LTSA is in effect through two major inspection cycles of the units. Scheduled payments to GE under the LTSA, which are subject to price escalation, 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 $13.3 million, $9.4 million, and $9.7 million for 2009, 2008, and 2007, respectively, which is included in maintenance expense in the statements of income. Remaining payments to GE under the LTSA are currently estimated to total $121 million over the next 11 years. However, the LTSA contains various cancellation provisions at the option of the Company.

The Company also has entered into a LTSA with Alstom Power, Inc. for the purpose of securing maintenance support for its Chevron Unit 5 combustion turbine plant. In summary, the LTSA stipulates that Alstom Power, Inc. will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. Alstom Power, Inc is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in the LTSA.

In general, this LTSA is in effect through two major inspection cycles. Scheduled payments to Alstom Power, Inc., which are subject to price escalation, are made at various intervals based on actual operating hours of the unit. Payments to Alstom Power, Inc. under the LTSA are currently estimated to total $22.3 million over the remaining term of the LTSA, which is approximately eight years. However, the LTSA contains various cancellation provisions at the option of the Company. Payments made to Alstom Power, Inc. under the LTSA 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. After the LTSA expires, the Company expects to replace it with a new contract with similar terms.

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 and nitrogen oxide emissions 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, 2009.

Total estimated minimum long-term obligations at December 31, 2009 were as follows:

	Commitments
	Natural Gas		Coal
	(in thousands)
2010	$	185,120	$	316,006
2011		154,004		322,858
2012		97,800		111,226
2013		75,708		23,005
2014		61,622		7,800
2015 and thereafter		182,662		—
Total	$	756,916	$	780,895

Additional commitments for fuel will be required to supply the Company’s future needs.

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SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. The creditworthiness of Southern Power is currently inferior to the creditworthiness of the traditional operating companies. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

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-MW natural gas combined cycle generating facility built at Plant Daniel (Facility). 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 formulary 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% 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 4% of the initial acquisition cost over the initial lease term. In April 2010, 18 months prior to the end of the initial lease, the Company must notify Juniper if the lease will be terminated. The Company may elect to renew the lease for 10 years. If the lease is renewed, the agreement calls for the Company to amortize an additional 17% 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. If the Company does not exercise either its purchase option or its renewal option, the Company could lose its rights to some or all of the 1,064 MWs of capacity at that time.

The lease provides for a residual value guarantee, approximately 73% 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 $3 million, $5 million, and $7 million for the fair market value of this residual value guarantee is included in the balance sheets at December 31, 2009, 2008, and 2007, respectively. Lease expenses were $26 million, $26 million, and $27 million in 2009, 2008, and 2007, respectively.

The Company estimates that its annual amount of future minimum operating lease payments under this arrangement, exclusive of any payment related to the residual value guarantee, as of December 31, 2009, are as follows:

	Minimum Lease Payments
	(in thousands)
2010	$	28,398
2011		28,291
2012 and thereafter		—
Total commitments	$	56,689

Other Operating 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 additional railcars that do not contain a purchase option. All of these leases are for the transport of coal to Plant Daniel.

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Mississippi Power Company 2009 Annual Report

The Company’s share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $4.0 million in 2009, $4.0 million in 2008, and $4.4 million in 2007. The Company’s annual railcar lease payments for 2010 through 2014 will average approximately $1.7 million and after 2014, lease payments total in aggregate approximately $1.6 million.

In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company’s share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of $0.6 million in 2009 and $0.6 million in 2008. The Company’s annual lease payments for 2010 through 2014 will average approximately $0.3 million for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $8.4 million in 2009 and $9.8 million in 2008 related to barges and tow/shift boats. The Company’s annual lease payments for 2010 through 2014 with respect to these barge transportation leases will average approximately $7.7 million.

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, 2009, there were 282 current and former employees of the Company participating in the stock option plan and there were 21 million shares of Southern Company common stock remaining available for awards under this plan. 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. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement the total cost is expensed at the grant date. 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. For certain stock option awards, a change in control will provide accelerated vesting.

The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company’s stock over a period equal to the expected term. The Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:

Year Ended December 31	2009			2008			2007
Expected volatility		15.6	%		13.1	%		14.8	%
Expected term(in years)		5.0			5.0			5.0
Interest rate		1.9	%		2.8	%		4.6	%
Dividend yield		5.4	%		4.5	%		4.3	%
Weighted average grant-date fair value	$	1.80		$	2.37		$	4.12

The Company’s activity in the stock option plan for 2009 is summarized below:

	Shares Subject			Weighted Average
	to Option			Exercise Price
Outstanding at December 31, 2008		1,431,127		$	31.72
Granted		452,956			31.39
Exercised		(26,217	)		18.64
Cancelled		(1,210	)		31.21
Outstanding at December 31, 2009		1,856,656		$	31.83
Exercisable at December 31, 2009		1,153,249		$	31.09

The number of stock options vested, and expected to vest in the future, as of December 31, 2009 was not significantly different from the number of stock options outstanding at December 31, 2009 as stated above. As of December 31, 2009, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.3 years and 4.8 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $4.3 million and $3.4 million, respectively.

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Mississippi Power Company 2009 Annual Report

As of December 31, 2009, there was $0.2 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.

For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option awards recognized in income was $0.9 million, $0.7 million, and $1.0 million, respectively, with the related tax benefit also recognized in income of $0.3 million, $0.3 million, and $0.4 million, respectively.

The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options to the Company’s employees are recognized in the Company’s financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company.

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $0.4 million, $3.7 million, and $2.2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.2 million, $1.4 million, and $0.9 million, respectively, for the years ended December 31, 2009, 2008, and 2007.

9. FAIR VALUE MEASUREMENTS

The fair value measurement is based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
At December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in thousands)
Assets:
Energy-related derivatives	$	—	$	563	$	—	$	563
Cash equivalents		60,000		—		—		60,000
Total	$	60,000	$	563	$	—	$	60,563
Liabilities:
Energy-related derivatives	$	—	$	42,297	$	—	$	42,297

Energy-related derivatives primarily consist of over-the-counter contracts. See Note 10 for additional information. The cash equivalents consist of securities with original maturities of 90 days or less. All of these financial instruments and investments are valued primarily using the market approach.

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Mississippi Power Company 2009 Annual Report

As of December 31, 2009, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

			Unfunded	Redemption	Redemption
As of December 31, 2009:	Fair Value		Commitments	Frequency	Notice Period
	(in thousands)
Cash equivalents:
Money market funds	$	60,000	None	Daily	Not applicable

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission, and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company’s investment in the money market funds.

As of December 31, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in thousands)
Long-term debt:
2009	$	491,410	$	497,933
2008	$	407,061	$	405,957

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

10. DERIVATIVES

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 its exposures, where possible, 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. The Company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

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 manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of three methods:

• Regulatory Hedges– Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

• Cash Flow Hedges– Gains and losses on energy-related derivatives designated as cash flow hedges, are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income (OCI) before being recognized in income in the same period as the hedged transactions are reflected in earnings.

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Mississippi Power Company 2009 Annual Report

• Not Designated– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At December 31, 2009, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Net Purchased	Longest Hedge	Longest Non-Hedge
mmBtu*	Date	Date
(in thousands)
24,000	2014	—

* mmBtu — million British thermal units

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2010 are immaterial.

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

	Asset Derivatives					Liability Derivatives
	Balance Sheet					Balance Sheet
Derivative Category	Location	2009		2008		Location	2009		2008
		(in thousands)					(in thousands)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:	Other current assets	$	446	$	761	Liabilities from risk management activities	$	19,454	$	28,660
	Other deferred charges and assets		105		—	Other deferred credits and liabilities		22,843		24,057
Total derivatives designated as hedging instruments for regulatory purposes		$	551	$	761		$	42,297	$	52,717
Derivatives designated as hedging instruments in cash flow hedges
Energy-related derivatives:	Other current assets	$	—	$	159	Liabilities from risk management activities	$	—	$	17
Derivatives not designated as hedging instruments
Energy-related derivatives:	Other current assets	$	12	$	443	Liabilities from risk management activities	$	—	$	614
Total		$	563	$	1,363		$	42,297	$	53,348

All derivative instruments are measured at fair value. See Note 9 for additional information.

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Mississippi Power Company 2009 Annual Report

At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

	Unrealized Losses							Unrealized Gains
	Balance Sheet							Balance Sheet
Derivative Category	Location	2009			2008			Location	2009		2008
		(in thousands)							(in thousands)
Energy-related derivatives:	Other regulatory assets, current	$	(19,454	)	$	(28,660	)	Other regulatory liabilities, current	$	446	$	761
	Other regulatory assets, deferred		(22,843	)		(24,057	)	Other regulatory liabilities, deferred		105		—
Total energy-related derivative gains (losses)		$	(42,297	)	$	(52,717	)		$	551	$	761

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in								Gain (Loss) Reclassified from Accumulated OCI into Income
Derivatives in Cash Flow	OCI on Derivative								(Effective Portion)
Hedging Relationships	(Effective Portion)									Amount
Derivative Category	2009		2008			2007			Statements of Income Location	2009		2008		2007
	(in thousands)									(in thousands)
Energy-related derivatives	$	—	$	(929	)	$	(41	)	Fuel	$	—	$	—	$	—

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial.

Contingent Features

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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2009, the fair value of derivative liabilities with contingent features was $3.9 million.

At December 31, 2009, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33.3 million.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to debt and preferred stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participated in certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

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Mississippi Power Company 2009 Annual Report

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2009 and 2008 are as follows:

	Operating		Operating		Net Income After Dividends
Quarter Ended	Revenues		Income		on Preferred Stock
			(in thousands)
March 2009	$	268,723	$	31,418	$	17,971
June 2009		286,681		40,899		21,933
September 2009		330,680		63,075		34,898
December 2009		263,337		20,665		10,165
March 2008	$	285,416	$	28,712	$	16,172
June 2008		297,932		39,410		24,005
September 2008		381,415		58,718		36,217
December 2008		291,779		20,488		9,566

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

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SELECTED FINANCIAL AND OPERATING DATA 2005-2009
Mississippi Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands)	$	1,149,421	$	1,256,542	$	1,113,744	$	1,009,237	$	969,733
Net Income after Dividends
on Preferred Stock (in thousands)	$	84,967	$	85,960	$	84,031	$	82,010	$	73,808
Cash Dividends
on Common Stock (in thousands)	$	68,500	$	68,400	$	67,300	$	65,200	$	62,000
Return on Average Common Equity (percent)		13.12		13.75		13.96		14.25		13.33
Total Assets (in thousands)	$	2,072,681	$	1,952,695	$	1,727,665	$	1,708,376	$	1,981,269
Gross Property Additions (in thousands)	$	95,573	$	139,250	$	114,927	$	127,290	$	158,084
Capitalization (in thousands):
Common stock equity	$	658,522	$	636,451	$	613,830	$	589,820	$	561,160
Redeemable preferred stock		32,780		32,780		32,780		32,780		32,780
Long-term debt		493,480		370,460		281,963		278,635		278,630
Total (excluding amounts due within one year)	$	1,184,782	$	1,039,691	$	928,573	$	901,235	$	872,570
Capitalization Ratios (percent):
Common stock equity		55.6		61.2		66.1		65.4		64.3
Redeemable preferred stock		2.8		3.2		3.5		3.6		3.8
Long-term debt		41.6		35.6		30.4		31.0		31.9
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Security Ratings:
First Mortgage Bonds —
Moody’s		—		—		—		—		—
Standard and Poor’s		—		—		—		—		—
Fitch		—		—		—		—		—
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-		AA-		AA-		AA-
Customers (year-end):
Residential		151,375		152,280		150,601		147,643		142,077
Commercial		33,147		33,589		33,507		32,958		30,895
Industrial		513		518		514		507		512
Other		180		183		181		177		176
Total		185,215		186,570		184,803		181,285		173,660
Employees (year-end)		1,285		1,317		1,299		1,270		1,254

II-382

SELECTED FINANCIAL AND OPERATING DATA 2005-2009 (continued)
Mississippi Power Company 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands):
Residential	$	245,357	$	248,693	$	230,819	$	214,472	$	209,546
Commercial		269,423		271,452		247,539		215,451		213,093
Industrial		269,128		258,328		242,436		211,451		190,720
Other		7,041		6,961		6,420		5,812		5,501
Total retail		790,949		785,434		727,214		647,186		618,860
Wholesale — non-affiliates		299,268		353,793		323,120		268,850		283,413
Wholesale — affiliates		44,546		100,928		46,169		76,439		50,460
Total revenues from sales of electricity		1,134,763		1,240,155		1,096,503		992,475		952,733
Other revenues		14,658		16,387		17,241		16,762		17,000
Total	$	1,149,421	$	1,256,542	$	1,113,744	$	1,009,237	$	969,733
Kilowatt-Hour Sales (in thousands):
Residential		2,091,825		2,121,389		2,134,883		2,118,106		2,179,756
Commercial		2,851,248		2,856,744		2,876,247		2,675,945		2,725,274
Industrial		4,329,924		4,187,101		4,317,656		4,142,947		3,798,477
Other		38,855		38,886		38,764		36,959		37,905
Total retail		9,311,852		9,204,120		9,367,550		8,973,957		8,741,412
Wholesale — non-affiliates		4,651,606		5,016,655		5,185,772		4,624,092		4,811,250
Wholesale — affiliates		839,372		1,487,083		1,026,546		1,679,831		896,361
Total		14,802,830		15,707,858		15,579,868		15,277,880		14,449,023
Average Revenue Per Kilowatt-Hour (cents):
Residential		11.73		11.72		10.81		10.13		9.61
Commercial		9.45		9.50		8.61		8.05		7.82
Industrial		6.22		6.17		5.61		5.10		5.02
Total retail		8.49		8.53		7.76		7.21		7.08
Wholesale		6.26		6.99		5.94		5.48		5.85
Total sales		7.67		7.90		7.04		6.50		6.59
Residential Average Annual Kilowatt-Hour Use Per Customer		13,762		13,992		14,294		14,480		14,111
Residential Average Annual Revenue Per Customer	$	1,614	$	1,640	$	1,545	$	1,466	$	1,357
Plant Nameplate Capacity Ratings (year-end) (megawatts)		3,156		3,156		3,156		3,156		3,156
Maximum Peak-Hour Demand (megawatts):
Winter		2,392		2,385		2,294		2,204		2,178
Summer		2,522		2,458		2,512		2,390		2,493
Annual Load Factor (percent)		60.7		61.5		60.9		61.3		56.6
Plant Availability Fossil-Steam (percent)		94.1		91.6		92.2		81.1		82.8
Source of Energy Supply (percent):
Coal		40.0		58.7		60.0		63.1		58.1
Oil and gas		43.6		28.6		27.1		26.1		24.4
Purchased power —
From non-affiliates		3.3		4.4		3.0		3.5		5.1
From affiliates		13.1		8.3		9.9		7.3		12.4
Total		100.0		100.0		100.0		100.0		100.0

II-383

SOUTHERN POWER COMPANY

FINANCIAL SECTION

II-384

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Power Company and Subsidiary Companies 2009 Annual Report

The management of Southern Power Company (the “Company”) 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 the 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. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

This Annual Report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

/s/ Ronnie L. Bates

Ronnie L. Bates
President and Chief Executive Officer

/s/ Michael W. Southern

Michael W. Southern
Senior Vice President and Chief Financial Officer

February 25, 2010

II-385

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southern Power Company

We have audited the accompanying consolidated balance sheets of Southern Power Company and Subsidiary Companies (the “Company”) (a wholly owned subsidiary of Southern Company) as of December 31, 2009 and 2008, 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, 2009. 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-407 to II-428) present fairly, in all material respects, the financial position of Southern Power Company and Subsidiary Companies at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

II-386

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power Company and Subsidiary Companies 2009 Annual Report

OVERVIEW

Business Activities

Southern Power Company and its wholly-owned subsidiaries (the Company) construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. The Company continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into power purchase agreements (PPAs) with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

In October 2009, the Company acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables, LLC, the developer of the project. The Company is constructing a biomass generating plant near Sacul, Texas with an estimated capacity of 100 megawatts (MWs). The generating plant will be fueled from wood waste. Construction commenced in late 2009 and the plant is expected to begin commercial operation in 2012. The output of the plant will be sold under a long-term PPA.

In December 2009, the Company acquired all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC (Broadway), an affiliate of LS Power. West Georgia was merged into the Company and the Company now owns a 669-MW nameplate capacity generating facility consisting of four combustion turbine natural gas generating units with oil back-up. The output from two units is sold under long-term PPAs.

In December 2009, the Company transferred all of the outstanding membership interests of DeSoto County Generating Company LLC (DeSoto) to Broadway as part of the acquisition of West Georgia.

The Company continued construction of an electric generating plant in Cleveland County, North Carolina. This plant will consist of four combustion turbine natural gas generating units with a total expected generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. The Company has entered into long-term PPAs for 540 MWs of the generating capacity of the plant.

As of December 31, 2009, the Company had units totaling 7,880 MWs nameplate capacity in commercial operation. The weighted average duration of the Company’s wholesale contracts exceeds 11.7 years, which reduces remarketing risk. The Company’s future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets. See FUTURE EARNINGS POTENTIAL herein for additional information.

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 include peak season equivalent forced outage rate (EFOR), return on invested capital (ROIC), and net income. EFOR defines the hours during peak demand times when the Company’s generating units are not available due to forced outages (the lower the better). ROIC is focused on earning a return on all invested capital that meets or exceeds the Company��s weighted average cost of capital. Net income is the primary measure of the Company’s financial performance. The Company’s actual performance in 2009 met or 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 2009 net income was $155.9 million, an $11.5 million increase over 2008. This increase was primarily due to increased margins associated with the operation of Plant Franklin Unit 3 for all of 2009, increased generation from the Company’s combined cycle units due to lower natural gas prices, and profit recognized under a construction contract with the Orlando Utilities Commission (OUC) whereby the Company provided engineering, procurement, and construction services to build a combined cycle unit for the OUC. These favorable impacts were partially offset by a loss recognized on the transfer of DeSoto to Broadway in December 2009, gains recognized in income in 2008 related to the sale of an undeveloped tract of land in Orange County, Florida to the OUC, and the receipt of a fee for participating in an asset auction as an unsuccessful bidder. Additionally, depreciation increased due to the completion of Plant Franklin Unit 3 in June 2008 and an increase in depreciation rates. Interest expense increased due to a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008.

II-387

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power Company and Subsidiary Companies 2009 Annual Report

The Company’s 2008 net income was $144.4 million, a $12.7 million increase over 2007. This increase was primarily due to increased capacity sales to requirements service customers, market sales of uncontracted generating capacity, a gain on the sale of an undeveloped tract of land in 2008, a loss on the gasifier portion of the integrated coal gasification combined cycle (IGCC) project in 2007, and the receipt of a fee for participating in an asset auction in 2008 as an unsuccessful bidder. These increases were partially offset by transmission service expenses and tariff penalties incurred in 2008, timing of plant maintenance activities, increased general and administrative expenses associated with the implementation of the Federal Energy Regulatory Commission (FERC) separation order, and increased depreciation associated with Plant Oleander Unit 5 and Plant Franklin Unit 3 being placed into commercial operation in December 2007 and June 2008, respectively.

The Company’s 2007 net income was $131.6 million, a $7.2 million increase over 2006. This increase was primarily due to increased energy sales due to more favorable weather in 2007. Also contributing to the increase were additional sales from the acquisition of Plant Rowan in September 2006. These increases were partially offset by the $10.7 million after tax loss as a result of the termination of the construction of the gasifier portion of the IGCC project.

RESULTS OF OPERATIONS

A condensed statement of income follows:

				Increase (Decrease)
	Amount			from Prior Year
	2009			2009			2008			2007
	(in millions)
Operating revenues	$	946.7		$	(366.9	)	$	341.5		$	195.0
Fuel		232.5			(192.3	)		186.1			93.4
Purchased power		143.9			(184.0	)		128.1			29.3
Other operations and maintenance		136.7			(11.1	)		12.7			39.7
Loss (gain) on sale of property		5.0			11.0			(6.0	)		—
Loss on IGCC project		—			—			(17.6	)		17.6
Depreciation and amortization		98.1			9.6			14.5			8.0
Taxes other than income taxes		16.9			(0.8	)		2.0			0.2
Total operating expenses		633.1			(367.6	)		319.8			188.2
Operating income		313.6			0.7			21.7			6.8
Interest expense		85.0			1.8			4.0			(1.0	)
Profit recognized on construction contract		13.3			13.3			—			—
Other income (expense), net		(0.4	)		(8.0	)		4.3			1.1
Income taxes		85.6			(7.3	)		9.3			1.7
Net income	$	155.9		$	11.5		$	12.7		$	7.2

Operating Revenues

Operating revenues in 2009 were $946.7 million, a $366.9 million (27.9%) decrease from 2008. This decrease was primarily due to lower natural gas prices that reduced energy revenues. This decrease was partially offset by increased capacity and energy revenues from the operation of Plant Franklin Unit 3 and a PPA relating to four units at Plant Dahlberg that began in June 2009.

Operating revenues in 2008 were $1.31 billion, a $341.5 million (35.1%) increase from 2007. This increase was primarily due to increased short-term energy revenues from uncontracted generating units, increased energy revenues due to higher natural gas prices, and increased revenues from a full year of operations at Plant Oleander Unit 5. These increases were partially offset by decreased demand under existing PPAs due to less favorable weather in 2008 compared to 2007. The increase in fuel revenues was accompanied by an increase in related fuel costs and did not have a significant impact on net income.

Operating revenues in 2007 were $972 million, a $195.0 million (25.1%) increase from 2006. This increase was primarily due to increased short-term energy sales, a full year of operations at Plant Rowan acquired in September 2006, new sales with EnergyUnited Electric Membership Cooperative (EnergyUnited), increased demand under existing PPAs with affiliates as a result of favorable weather within the Southern Company system service territory, and higher fuel revenues due to an increase in natural gas prices in 2007. The increase in fuel revenues was accompanied by an increase in related fuel costs and did not have a significant impact on net income.

II-388

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

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 the 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:

	2009		2008		2007
	(in millions)
Capacity revenues —
Affiliates	$	287.6	$	279.2	$	279.7
Non-affiliates		185.7		165.2		136.9
Total		473.3		444.4		416.6
Energy revenues —
Affiliates		192.8		263.6		227.1
Non-affiliates		173.8		249.0		189.1
Total		366.6		512.6		416.2
Total PPA revenues	$	839.9	$	957.0	$	832.8

Wholesale revenues that were not covered by PPAs totaled $98.9 million in 2009, which included $64.0 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $349.2 million in 2008, which included $95.5 million of revenues from affiliated companies. Wholesale revenues that were not covered by PPAs totaled $131.0 million in 2007, which included $40.0 million of revenues from affiliated companies. These wholesale sales were made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These non-PPA wholesale revenues will vary from year to year 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 system fleet of generating plants (power pool).

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the Company. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

Details of the Company’s fuel and purchased power expenditures are as follows:

	2009		2008		2007
	(in millions)
Fuel	$	232.5	$	424.8	$	238.7
Purchased power-non-affiliates		79.3		132.2		64.6
Purchased power-affiliates		64.6		195.8		135.3
Total fuel and purchased power expenses	$	376.4	$	752.8	$	438.6

In 2009, total fuel and purchased power expenses decreased by $376.4 million (50.0%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas and a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume decreased 25.2% primarily due to increased generation at the Company’s combined cycle units as a result of lower natural gas prices. These decreases were partially offset by a 31.2% increase in generation at the Company’s combined cycle units as a result of lower natural gas prices. In 2008, total fuel and purchased power expenses increased by $314.2 million (71.6%) compared to 2007. This increase was driven by a 58.9% increase in generation due to operations at Plant Franklin Unit 3, an 11.9% increase in the average cost of natural gas, and a 107.9% increase in the average cost of purchased power. In 2007, total fuel and purchased power expenses increased by $122.7 million (38.8%) compared to 2006. This increase was driven by a 43.7% increase in generation at Plants Wansley and Dahlberg, a 5.2% increase in the average cost of natural gas, increased purchases of lower cost energy resources from the power pool and non-affiliates, and contracts with Georgia Electric Membership Corporations and Dalton Utilities.

In 2009, fuel expense decreased by $192.3 million (45.3%) compared to 2008. This decrease was driven by a 56.0% decrease in the average cost of natural gas. This decrease was partially offset by a 31.2% increase in generation at the Company’s combined cycle units as a result of lower natural gas prices. In 2008, fuel expense increased by $186.1 million (78.0%) compared to 2007. This increase was driven by a 58.9% increase in generation primarily due to operations at Plant Franklin Unit 3 and an 11.9% increase in the average cost of natural gas. In 2007, fuel expense increased by $93.4 million (64.3%) compared to 2006. This increase was driven by a 43.7% increase in generation at Plants Wansley and Dahlberg and a 5.2% increase in the average cost of natural gas.

II-389

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

In 2009, purchased power expense decreased $184.0 million (56.1%) compared to 2008, primarily due to a 41.3% decrease in the average cost of purchased power. Additionally, purchased power volume in 2009 decreased 25.2% due to increased generation at the Company’s combined cycle units as a result of lower natural gas prices. Purchased power expense increased $128.1 million (64.1%) in 2008 when compared to 2007, primarily due to a 107.9% increase in the average cost of purchased power. Purchased power expense increased $29.3 million (17.1%) in 2007 when compared to 2006, primarily due to increased purchases of lower cost energy resources from the power pool and non-affiliates and contracts with Georgia Electric Membership Corporation and Dalton Utilities.

The Company’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. The Company is responsible for the cost of fuel for units that are not covered under PPAs. Power from these units is sold into the market or sold to affiliates under the IIC.

Purchased power expenses will vary depending on demand and the availability and cost of generating resources available throughout the Southern Company system and other contract resources. Load requirements are submitted to the power 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.

Other Operations and Maintenance Expenses

In 2009, other operations and maintenance expenses decreased $11.1 million (7.5%) compared to 2008. This decrease was due primarily to transmission tariff penalties recognized in 2008, reduced transmission expenses due to a decrease in power sales into the market, and the timing of plant outages.

In 2008, other operations and maintenance expenses increased $12.7 million (9.4%) compared to 2007. This increase was due primarily to the timing of plant maintenance activities, transmission tariff penalties, and additional administrative and general expenses as a result of costs incurred to implement the FERC compliance plan. See Note 3 to the financial statements under “FERC Matters — Intercompany Interchange Contract” for additional information.

In 2007, other operations and maintenance expenses increased $39.7 million (41.7%) compared to 2006. This increase was due primarily to a full year of operations at Plant DeSoto and Plant Rowan acquired in June 2006 and September 2006, respectively, and additional administrative and general expenses as a result of costs incurred to implement the FERC compliance plan. See Note 3 to the financial statements under “FERC Matters — Intercompany Interchange Contract” for additional information.

Loss (Gain) on Sale of Property

In December 2009, the Company recorded a loss of $5.0 million on the transfer of DeSoto to Broadway. See FUTURE EARNINGS POTENTIAL — “Acquisitions and Divestitures — West Georgia Acquisition and Plant DeSoto Divestiture” herein and Note 2 to the financial statements under “Acquisitions and Divestitures — West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture” for additional information.

In January 2008, the Company recorded a gain of $6.0 million on the sale of an undeveloped tract of land.

Loss on IGCC Project

In November 2007, the Company and the OUC mutually agreed to terminate the construction of the gasifier portion of the IGCC project, originally planned as a joint venture; however, the Company continued construction of the gas-fired combined cycle generating facility, owned solely by the OUC. The Company recorded a loss in the fourth quarter 2007 of $17.6 million related to the cancellation of the gasifier portion of the IGCC project. This loss consists of the write-off of construction costs of $14.0 million and an accrual for termination payments of $3.6 million. All termination payments were completed in 2008.

II-390

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Depreciation and Amortization

In 2009, depreciation and amortization increased $9.6 million (10.9%) compared to 2008. This increase was primarily due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented during 2009.

In 2008, depreciation and amortization increased $14.5 million (19.7%) due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented in January 2008.

In 2007, depreciation and amortization increased $8.0 million (12.2%) due to the completion of Plant Oleander Unit 5 in December 2007 and additional depreciation related to Plants DeSoto and Rowan acquired in June 2006 and September 2006, respectively, and higher depreciation rates from a study adopted in March 2006.

See FUTURE EARNINGS POTENTIAL — “Other Matters” herein for additional information regarding the Company’s ongoing review of depreciation estimates. See also Note 1 to the financial statements under “Depreciation” for additional information.

Taxes Other Than Income Taxes

The 2009 decrease in taxes other than income taxes was not material.

In 2008, taxes other than income taxes increased $2.0 million (12.4%) compared to 2007. This increase was primarily due to property taxes related to the completion of Plant Oleander Unit 5 and Plant Franklin Unit 3 in December 2007 and June 2008, respectively.

The 2007 increase in taxes other than income taxes was not material.

Interest Expense, Net of Amounts Capitalized

In 2009, interest expense, net of amounts capitalized increased $1.8 million (2.1%) compared to 2008. This increase was primarily due to a $5.5 million decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a $1.7 million decrease in short-term borrowing levels during 2009 and a decrease in amortization of interest rate derivatives of $2.1 million.

In 2008, interest expense, net of amounts capitalized increased $4.0 million (5.1%) compared to 2007. This increase was primarily the result of a decrease in capitalized interest as a result of the completion of Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels in 2008.

In 2007, interest expense, net of amounts capitalized decreased $1.0 million (1.2%) compared to 2006. This decrease was primarily due to additional capitalized interest of $10.9 million on active construction projects and reduced interest on commercial paper of $2.0 million due to lower borrowing levels. This decrease was partially offset by an $11.9 million increase in interest on $200 million of senior notes that were issued in November 2006.

Profit Recognized on Construction Contract

Profit recognized on the construction contract with the OUC whereby the Company has provided engineering, procurement, and construction services to build a combined cycle unit for the OUC was $13.3 million in 2009. No profit or loss on this contract was recognized in 2008 or 2007.

Other Income (Expense), Net

Other income (expense), net was an expense of $0.4 million in 2009 versus income of $7.6 million in 2008. This change was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction.

Other income (expense), net increased $4.3 million (131.1%) in 2008. This increase was primarily due to a $6.4 million fee received in 2008 for participating in an asset auction. The Company was not the successful bidder in the asset auction.

Changes in other income (expense), net in 2007 were not material.

II-391

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Income Taxes

In 2009, income taxes decreased $7.3 million (7.8%) compared to 2008. This decrease was due to changes in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction, lower state income taxes, and tax benefits received under convertible investment tax credits. Higher pre-tax earnings partially offset these decreases. See Note 5 to the financial statements for additional information.

Income taxes increased $9.3 million (11.2%) in 2008 and $1.7 million (2.1%) in 2007 primarily due to higher pre-tax earnings and changes in the Section 199 production activities deduction.

Effects of Inflation

The Company is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on the Company’s results of operations has not been substantial.

FUTURE EARNINGS POTENTIAL

General

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company’s competitive wholesale business. These factors include the Company’s ability to achieve sales growth while containing costs. The level of future earnings also depends on numerous factors including regulatory matters (such as those related to affiliate contracts), creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and the Company’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recent recessionary conditions have lowered demand and have negatively impacted capacity revenues under the Company’s PPAs where the amounts purchased are based on demand. The Company is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery will impact future earnings.

The Company’s system generating capacity increased 325 MWs due to the acquisition of West Georgia and divestiture of DeSoto in December 2009 as described herein. In general, the Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities which are optimized by limited energy trading activities. See “Acquisitions and Divestitures” and “Construction Projects” herein for additional information.

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. The Company expects that many areas of the market will need capacity in 2016.

The Company’s PPAs consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. The Company typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that the Company serve the customer’s capacity and energy requirements from a combination of the customer’s own generating units and from Company resources not dedicated to serve unit or block sales. The Company has rights to purchase power provided by the requirements customers’ resources when economically viable.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

The Company has entered into the following PPAs over the past three years:

						Contract
	Date	Megawatts			Plant	Term
2009
Municipal Electric Authority of Georgia (MEAG Power)(a)	December 2009		157	(g)	West Georgia		12/09-4/29
Georgia Energy Cooperative, Inc. (GEC)(a)	December 2009		151		West Georgia		6/10-5/30
Austin Energy(b)	October 2009		100		Nacogdoches		6/12-5/32
Seminole Electric Cooperative, Inc. (Seminole)(c)	June 2009		509		Oleander		1/16-5/21
2008
North Carolina Municipal Power Agency No. 1 (NCMPA1)	December 2008		180		Cleveland		1/12-12/31
North Carolina Electric Membership Corporation (NCEMC)	November 2008		180		Cleveland		1/12-12/36
NCEMC	November 2008		180	(d)	Cleveland		1/12-12/36
EnergyUnited	November 2008		100		Purchased(e)		1/12-12/21
The Energy Authority, Inc.	August 2008		151		Rowan		1/11-12/14
Georgia Electric Membership Corporations (EMCs)(f)	July 2008		360	(g)	Unassigned		1/10-12/34	(f)
Florida Municipal Power Agency (FMPA)(h)	July 2008		85		Stanton		10/13-9/23
2007
Progress Energy Carolina Inc.	December 2007		155		Rowan		1/10-12/10
Progress Energy Carolina Inc.	December 2007		160		Wansley		1/11-12/11
Georgia Power	April 2007		561		Wansley		6/10-5/17
Georgia Power	April 2007		292		Dahlberg		6/10-5/25
Progress Energy Carolina Inc.	February 2007		150		Rowan		1/10-12/19

(a)	Assumed contract through the West Georgia acquisition in 2009.
(b)	Assumed contract through the Nacogdoches acquisition in 2009. Commercial operation of Plant Nacogdoches is expected to begin in June 2012.
(c)	This agreement is an extension of the current agreement with Seminole for Plant Oleander.
(d)	Power purchases under this agreement will increase over the term of the agreement. 45 MWs will be sold from 2012 through 2016, 90 MWs will be sold from 2017 through 2018, and 180 MWs will be sold from 2019 through 2036.
(e)	Power to serve this agreement will be purchased under a third party agreement for resale to EnergyUnited. The purchases will be resold at cost.
(f)	These agreements are extensions of current agreements with 10 Georgia EMCs. Eight agreements were extended from 2010 through 2031 and two agreements were extended from 2013 through 2034.
(g)	Represents average annual capacity purchases.
(h)	This agreement is an extension of the current agreement with FMPA for Plant Stanton.

The Company has PPAs with some of Southern Company’s traditional operating companies and with other investor owned utilities, independent power producers, municipalities, and electric cooperatives. Although some of the Company’s PPAs are with the traditional operating companies, the Company’s generating facilities are not in the traditional operating companies’ regulated rate bases, and the Company is not able to seek recovery from the traditional operating companies’ ratepayers for construction, repair, environmental, or maintenance costs. The Company expects that the capacity payments in the PPAs will produce sufficient cash flow to cover 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 and demand under the Company’s PPAs.

As a general matter, existing PPAs provide that the purchasers are responsible for either procuring the fuel or reimbursing the Company for 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 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 energy charges based on dollars-per-MW hour. In general, the Company has long-term service contracts with General Electric and Siemens AG to reduce its exposure to certain operation and maintenance costs relating to such vendors’ applicable equipment. See Note 7 to the financial statements under “Long-Term Service Agreements” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Many of the Company’s PPAs have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that Standard and Poor’s Rating Services, a division of the McGraw Hill Companies, Inc. (S&P) or Moody’s Investors Service (Moody’s) downgrades the credit ratings of the counterparty to an unacceptable credit rating or if 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.

The Company has entered into long-term power sales agreements for an average of 84% of its available capacity for the next five years and 74% of its available capacity for the next 10 years as follows:

	2010-			2012-			2014-			2016-			2018-
	2011			2013			2015			2017			2019
Average available capacity (MWs)(a)		7,964			8,774			8,774			8,494			8,494
Average contracted capacity (MWs)		6,940			7,199			7,083			5,432			4,959
Percent contracted		87	%		82	%		81	%		64	%		58	%

(a) Includes confirmed third party power purchases for 2010 through 2019.    

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. 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; 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 significantly affect the Company.

New environmental legislation or regulations, such as requirements related to greenhouse gases 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.

Because 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 cannot be determined at this time.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions renewable energy standards, and energy efficiency standards continue to be considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and 20% by 2020. Similar legislation is being considered by the Senate. The financial and operational impact of such legislation, if enacted, will depend on a variety of factors. These factors include the specific greenhouse gas emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on natural gas prices, and cost recovery through PPAs. There can be no assurance that any legislation will be enacted or as to the ultimate form of any legislation. Additional or alternative legislation may be adopted as well.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

In April 2007, the U.S. Supreme Court ruled that the Environmental Protection Agency (EPA) has authority under the Clean Air Act to regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published a final determination, which became effective on January 14, 2010, that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. On September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. The EPA also published a proposed rule governing how these programs would be applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and any legal challenges.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. A nonbinding agreement was announced during the most recent round of negotiations in December 2009 that included a pledge from both developed and developing countries to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations cannot be determined at this time.

Although the outcome of federal, state, or international initiatives cannot be determined at this time, mandatory restrictions on the Company’s greenhouse gas emissions or requirements relating to renewable energy or energy efficiency on the federal or state level are likely to result in significant additional compliance costs, including significant capital expenditures. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through PPAs. Further, higher costs that are recovered through regulated rates at other utilities could contribute to an overall reduction in demand for electricity, which could negatively impact the Company’s results of operations, cash flows, and financial condition.

In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units owned by the Company were approximately 6 million metric tons. The preliminary estimate of carbon dioxide emissions from these units in 2009 is approximately 7 million metric tons. The level of carbon dioxide emissions from year to year will be dependent on the level of generation, which is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.

The Company continues to evaluate its future energy and emissions profiles and is participating in voluntary programs to reduce greenhouse gas emissions and to help develop and advance technology to reduce emissions, including the construction of a biomass plant in Sacul, Texas.

Carbon Dioxide Litigation

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

In February 2004, the EPA finalized the Industrial Boiler (IB) MACT rule, which imposed limits on hazardous air pollutants from industrial boilers, including biomass boilers. Compliance with the final rule was scheduled to begin in September 2007; however, in response to challenges to the final rule, the U.S. Court of Appeals for the District of Columbia Circuit vacated the IB MACT rule in its entirety in July 2007 and ordered the EPA to develop a new IB MACT rule. In September 2009, the deadline to promulgate a proposed rule was extended from July 15, 2009 to April 15, 2010, with a final rule required by December 16, 2010. The EPA is currently developing the new rule and may change the methodology to determine the MACT limits for industrial boilers.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. The Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be immaterial. The Company is receiving investment tax credits (ITCs) under the renewable energy incentives related to the Nacogdoches biomass facility which will have a material impact on cash flows and net income. On December 8, 2009, President Obama announced proposals to accelerate job growth that include an extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant impact on the future cash flow and net income of the Company. The Company is currently assessing the other financial implications of the ARRA.

The ultimate impact of these matters cannot be determined at this time.

Internal Revenue Code Section 199 Domestic Production Deduction

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Acquisitions and Divestitures

Nacogdoches Acquisition

On October 8, 2009, the Company acquired all of the outstanding membership interests of Nacogdoches from American Renewables LLC, the original developer of the project, for approximately $50.1 million in cash consideration. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through December 31, 2009 were $86.6 million. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032 or until a contractual limit of $2.3 billion in billings is reached. See Note 2 to the financial statements under “Acquisitions and Divestitures –Nacogdoches Power LLC Acquisition” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

West Georgia Acquisition and Plant DeSoto Divestiture

On December 17, 2009, the Company acquired all of the outstanding membership interests of West Georgia from Broadway, an affiliate of LS Power. The acquisition agreement provided for the transfer of all the outstanding membership interests of DeSoto from the Company to Broadway and the payment by the Company of approximately $144.0 million in cash consideration. West Georgia was merged into the Company and the Company now owns a 669-MW nameplate capacity generating facility consisting of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with MEAG Power and GEC. The MEAG Power agreement began in 2009 and expires in 2029. The GEC agreement begins in 2010 and expires in 2030. See Note 2 to the financial statements under “Acquisitions and Divestitures — West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture” for additional information.

Construction Projects

Cleveland County Units 1-4

In December 2008, the Company announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. Costs incurred through December 31, 2009 were $62.7 million. The total estimated construction cost is expected to be between $350 million and $400 million, which is included in the capital program estimates described under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein.

The Company has also entered into PPAs with NCEMC and NCMPA1 for a portion of the generating capacity from the plant that will begin in 2012 and expire in 2036 and 2031, respectively. NCEMC will purchase 180 MWs of capacity that will be supported by one unit at the plant and will purchase capacity from a second unit at the plant that will increase to 180 MWs over a seven-year phase-in period. NCMPA1 will purchase 180 MWs from a third unit at the plant. The NCEMC PPAs were approved by the Rural Utilities Service on March 6, 2009.

Nacogdoches Biomass Plant

The Company is currently constructing a biomass plant in Sacul, Texas. See “Acquisitions and Divestitures — Nacogdoches Acquisition” herein and Note 2 to the financial statements under “Acquisitions and Divestitures — Nacogdoches Power LLC Acquisition” for additional information.

Other Matters

The Company completed depreciation studies in 2008 and 2009. The composite depreciation rates for its property, plant, and equipment were updated in these studies. These changes in estimates arise from changes in useful life assumptions for certain components of plant in service. These changes increased depreciation expense prospectively beginning January 1, 2008 and January 1, 2009 and reduced net income. The net income impacts of these changes were $2.8 million and $3.1 million in 2008 and 2009, respectively. See Note 1 to the financial statements under “Depreciation” for additional information. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could have a material impact on net income in the near term. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” herein for additional information.

From time to time, the Company is involved in various matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. 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 and other damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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. See Note 3 to the financial statements for information regarding material issues.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Revenue Recognition

The Company’s revenue recognition depends on appropriate classification and documentation of transactions in accordance with generally accepted accounting principles (GAAP). 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 9 to the financial statements. 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 (including purchased capacity);

• Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged; and

• Assessing hedge effectiveness at inception and throughout the contract term

Normal Sale and Non-Derivative Transactions

The Company has entered into capacity contracts that provide for the sale of electricity and that involve physical delivery in quantities within the Company’s available generating capacity. These contracts either do not meet the definition of a derivative or are designated as normal sales, thus exempting them from fair value accounting in accordance with GAAP. As a result, such transactions are accounted for as executory contracts; additionally, the related revenue is recognized on an accrual basis in amounts equal to the lesser of the cumulative levelized amount or the cumulative amount billable under the contract over the respective contract periods. Revenues are recorded on a gross or net basis in accordance with GAAP. Contracts recorded on the accrual basis represented the majority of the Company’s operating revenues for the year ended December 31, 2009.

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 and purchases of electricity, which meet the definition of a derivative and that are not designated as normal sales and purchases or designated as cash flow hedges, are marked to market and recorded directly through net income. Net unrealized gains (losses) on such contracts recognized in wholesale revenues for the years ended December 31, 2009 and 2008 were $5.3 million and $(1.9) million, respectively. Mark-to-market transactions were immaterial in 2007.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Percentage of Completion

The Company is currently engaged in a long-term contract for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Construction activities commenced in 2006 and were substantially completed in 2009. Billings and costs are recognized using the percentage of completion method. The Company utilizes the cost-to-cost approach as this method is less subjective than relying on assessments of physical progress. The percentage of completion represents the percentage of the total costs incurred to the estimated total cost of the contract. Billings and costs are recognized on a net basis in other income (expense) by applying this percentage to the total billings and estimated costs of the contract.

Impairment of Long Lived Assets and Intangibles

The Company’s investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company’s intangible assets consist of acquired PPAs that are amortized over the term of the PPAs and goodwill resulting from acquisitions. The Company evaluates the carrying value of these assets in accordance with accounting standards whenever indicators of potential impairment exist, or annually in the case of goodwill. 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, a significant decrease in market prices, and the inability to remarket generating capacity for an extended period. 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; and

• Future operating costs.

Acquisition Accounting

The Company has been engaged in a strategy of acquiring assets. The Company has accounted for these acquisitions under the purchase method in accordance with GAAP. Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price of each acquisition was allocated to the fair value of the identifiable assets and liabilities. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions after December 31, 2008 have been expensed as incurred.

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, in accordance with accounting standards, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. 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) or state revenue department interpretations of existing regulations.

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

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

• Resolution or progression of new or existing matters through the legislative process, the court systems, the IRS, state revenue departments, the FERC, or the EPA.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Depreciation

Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets’ estimated useful lives determined by management. The primary assets in property, plant, and equipment are power plants, all of which have an estimated composite life ranging from 24 to 35 years. These lives reflect a weighted average of the significant components (retirement units) that make up the plants. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. See Note 1 to the financial statements under “Depreciation” for a discussion of changes in depreciation assumptions made by the Company effective January 1, 2008 and January 1, 2009.

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.

Convertible Investment Tax Credits

Under the ARRA, certain costs related to the Nacogdoches plant construction are eligible for ITCs or cash grants. The Company has elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized over the life of the asset, and the tax basis of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. This basis difference will reverse and be recorded to income tax expense over the useful life of the asset once placed in service. The credits received during the year will be shown within operating activities in the consolidated statements of cash flows.

New Accounting Standards

Variable Interest Entities

In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted this new guidance effective January 1, 2010 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition remained stable at December 31, 2009. The Company has successfully accessed the commercial paper market as needed during 2009. There was $118.9 million of commercial paper outstanding as of December 31, 2009. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet its future capital and liquidity needs. Market rates for committed credit have increased and the Company may be subject to higher costs as its existing facilities are replaced or renewed. See “Sources of Capital” herein for additional information on lines of credit.

Net cash provided from operating activities totaled $318.1 million in 2009, increasing 20.4% from 2008. This increase is primarily due to a reduction in costs incurred on the OUC construction contract, receipt of convertible investment tax credits, and timing of tax payments. Net cash used for investing activities totaled $364.1 million in 2009, increasing 324.5% from 2008. This increase was primarily due to the Nacogdoches and West Georgia acquisitions in October 2009 and December 2009, respectively. Gross property additions to utility plant of $137.1 million in 2009 were primarily related to the construction of the Cleveland County and Nacogdoches facilities. Net cash provided from financing activities was $15.2 million in 2009, compared to $140.6 million used in 2008. This change was primarily due to the issuance of short-term debt in 2009.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Net cash provided from operating activities totaled $264.3 million in 2008, decreasing 16.2% from 2007. This decrease is primarily due to cash outflows for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Net cash used for investing activities totaled $85.8 million in 2008, decreasing 53.4% from 2007. This decrease was primarily due to the completion of Plant Oleander Unit 5 in 2007 and the completion of Plant Franklin Unit 3 in 2008. Gross property additions to utility plant of $50.0 million in 2008 were primarily related to the completion of Plant Franklin Unit 3. Net cash used for financing activities was $140.6 million in 2008, decreasing 12.9% from 2007. This decrease was primarily due to reduced levels of short-term debt in 2008.

Net cash provided from operating activities totaled $315.4 million in 2007, increasing 29.8% from 2006. This increase was primarily due to the increase in sales due to favorable weather and cash received under billings for the engineering, procurement, and construction services to build a combined cycle unit for the OUC. Net cash used for investing activities totaled $183.9 million in 2007, decreasing 61% from 2006. This decrease was primarily due to the acquisition of Plants DeSoto and Rowan in June 2006 and September 2006, respectively. Gross property additions to utility plant of $139.2 million in 2007 were primarily related to the on-going construction activity at Plant Franklin Unit 3 and the completion of construction at Plant Oleander Unit 5. Net cash used for financing activities was $161.5 million in 2007 compared to $233.4 million provided to the Company in 2006. This change was primarily due to the cash proceeds of $200 million from the issuance of 30-year senior notes in 2006 and borrowings and equity contributions to finance the acquisitions of Plants DeSoto and Rowan.

Significant asset changes in the balance sheet during 2009 include increases related to the West Georgia and Nacogdoches acquisitions. Construction work in progress increased due to Cleveland County and Nacogdoches construction activities. Prepaid long-term service agreements increased due to the timing of outage activities. Additionally, prepaid income taxes decreased due to the timing of income tax payments. Cash decreased due to the West Georgia and Nacogdoches acquisitions and increased construction activity.

Significant asset changes in the balance sheet during 2008 include increases in accounts receivable related to higher energy revenues due to an increase in natural gas prices, increases in prepaid long-term service agreements due to the timing of outage activities, and an increase in cash due to a reduction of investing activities of the Company in 2008 due to the completion of construction projects at Plant Oleander Unit 5 in December 2007 and Plant Franklin Unit 3 in June 2008.

Significant liability and stockholder’s equity changes in the balance sheet during 2009 include the issuance of $118.9 million in notes payable, an increase in accounts payable related to construction projects, and a decrease in net billings in excess of cost due to the timing of scheduled payments and costs incurred with regard to the OUC construction contract. In 2009, the Company also paid $106.1 million in dividends to Southern Company.

Significant liability and stockholder’s equity changes in the balance sheet during 2008 include the payment of short-term debt obligations, increases in affiliate payables due to increases in natural gas and purchased power prices, a reduction of other current liabilities due to payment of IGCC termination costs, and a decrease in the net billings in excess of cost on the OUC construction contract due to on-going construction activities. In 2008, the Company also paid $94.5 million in dividends to Southern Company.

Sources of Capital

The Company may use operating cash flows, external funds, or equity capital or loans 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. However, the amount, type, and timing of any financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.

The Company’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, at December 31, 2009, the Company had $400 million of committed credit arrangements with banks that expire in 2012. There were no borrowings under this facility outstanding at December 31, 2009. Proceeds from 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 6 to the financial statements under “Bank Credit Arrangements” for additional information.

II-401

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

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, 2009, there was $118.9 million of commercial paper outstanding. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

Management believes that the need for working capital can be adequately met by utilizing cash balances, commercial paper programs, and lines of credit.

Financing Activities

During 2009 and 2008, the Company did not issue any new long-term securities.

The issuance of all securities by the Company is generally subject to regulatory approval by the FERC. 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, as amended (1933 Act). The amounts of securities authorized by the FERC, 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.

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 and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, and energy price risk management. At December 31, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $339 million. At December 31, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $984 million. Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

In addition, through the acquisition of Plant Rowan, the Company assumed PPAs with Duke Energy and NCMPA1 that could require collateral, but not accelerated payment, in the event of a downgrade of the Company’s credit. The Duke Energy PPA defines the downgrade to be below BBB- or Baa3. The NCMPA1 PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade for both PPAs.

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 takes 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.

At December 31, 2009, 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. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term. However, the impact on future financing costs cannot be determined at this time.

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. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

II-402

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

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

	2009			2008
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	3.4		$	3.4
Contracts realized or settled		(2.0	)		1.4
Current period changes(a)		(4.9	)		(1.4	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(3.5	)	$	3.4

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

The decreases in the fair value positions of the energy-related derivative contracts for the years ended December 31, 2009 and December 31, 2008 were $6.9 million and $0.0 million, respectively, which is due to both volume and price changes in power and natural gas positions.

The net hedge positions at December 31, 2009 and December 31, 2008 and respective period end dates that support these changes are as follows:

	December 31, 2009			December 31, 2008
Power (net sold)
Megawatt hours (MWH) (in millions)		2.6			0.3
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	(0.38	)	$	(2.29	)
Natural gas (net purchase)
Commodity – million British thermal unit (mmBtu)		9.0			1.9
Location basis – million mmBtu		2.0			—
Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.29		$	(2.16	)
Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	(0.04	)		—

At December 31, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as assets/(liabilities) as follows:

Asset (Liability) Derivatives	2009			2008
	(in millions)
Cash flow hedges	$	(2.5	)	$	(0.8	)
Not designated		(1.0	)		4.2
Total fair value	$	(3.5	)	$	3.4

Gains and losses on energy-related derivatives used by the Company to hedge anticipated purchases and sales are initially deferred in other comprehensive income before being recognized in income in the same period as the hedged transaction. Gains and losses on derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years ended December 31, 2009 and December 31, 2008 for energy-related derivative contracts that are not hedges were $(5.2) million and $0.9 million, respectively.

II-403

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	December 31, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(3.5	)		(3.2	)		(0.4	)		0.1
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(3.5	)	$	(3.2	)	$	(0.4	)	$	0.1

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note 8 to the financial statements for further discussion on fair value measurements.

The Company is exposed to market-price risk in the event of nonperformance by counterparties to energy-related derivative contracts. The Company’s policy is to enter into derivative agreements with counterparties that have investment grade credit ratings by S&P 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 Note 1 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The capital program of the Company is currently estimated to be $627.4 million for 2010, $856.5 million for 2011, and $379.0 million for 2012. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and the Company’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. The Company is currently constructing four combustion turbine units in North Carolina and a biomass generating facility in Texas. See FUTURE EARNINGS POTENTIAL — “Construction Projects” herein and Note 2 to the financial statements under “Acquisitions and Divestitures — Nacogdoches Power LLC Acquisition” for additional information.

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, and other purchase commitments are as follows. See Notes 1, 6, 7, and 9 to the financial statements for additional information.

II-404

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Contractual Obligations

			2011-		2013-		After		Uncertain
	2010		2012		2014		2014		Timing(c)		Total
	(in millions)
Long-term debt(a) —
Principal	$	—	$	575.0	$	—	$	725.0	$	—	$	1,300.0
Interest		74.3		148.6		76.7		306.1		—		605.7
Energy-related derivative obligations(b)		8.1		0.5		—		—		—		8.6
Operating leases		0.6		1.0		1.0		22.3		—		24.9
Unrecognized tax benefits and interest(c)		—		—		—		—		0.1		0.1
Purchase commitments(d) —
Capital(e)		627.4		1,235.5		—		—		—		1,862.9
Natural gas(f)		165.8		323.9		239.5		277.6		—		1,006.8
Biomass fuel(g)		—		17.0		35.1		127.6		—		179.7
Purchased power(h)		13.6		57.0		102.0		295.2		—		467.8
Long-term service agreements(i)		46.6		101.2		78.9		953.6		—		1,180.3
Total	$	936.4	$	2,459.7	$	533.2	$	2,707.4	$	0.1	$	6,636.8

(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)	For additional information, see Notes 1 and 9 to the financial statements.
(c)	The timing related to the realization of $0.1 million in unrecognized tax benefits and interest payments cannot be reasonably and reliably estimated due to uncertainties in the timing of the effective settlement of tax positions. See Note 5 to the financial statements for additional information.
(d)	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 $136.7 million, $147.7 million, and $135.0 million, respectively.
(e)	The Company forecasts capital expenditures over a three-year period. Amounts represent estimates for potential plant acquisitions and new construction as well as ongoing capital improvements.
(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, 2009.
(g)	Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases for Plant Nacogdoches. Plant Nacogdoches is expected to begin commercial operation in 2012. Amounts reflected include price escalation based on inflation indices.
(h)	Purchased power commitments of $35.4 million in 2011-2012, $72.9 million in 2013-2014, and $279.3 million after 2014 will be resold under a third party agreement to EnergyUnited. The purchases will be resold at cost.
(i)	Long-term service agreements include price escalation based on inflation indices.

II-405

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2009 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning environmental regulations and expenditures, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, impact of the American Recovery and Reinvestment Act of 2009, estimated sales and purchases under new power sale and purchase agreements, impacts of revisions to depreciation estimates, start and completion of construction projects, plans and estimated costs for new generation resources, 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, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, particulate matter, and other substances, and also changes in 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 recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• advances in technology;

• state and federal rate regulations;

• the ability to control costs and avoid cost overruns during the development and construction of facilities;

• 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 and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• 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, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

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

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

II-406

CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Southern Power Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2007
	(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	394,366		$	667,979		$	416,648
Wholesale revenues, affiliates		544,415			638,266			547,229
Other revenues		7,870			7,296			8,137
Total operating revenues		946,651			1,313,541			972,014
Operating Expenses:
Fuel		232,466			424,800			238,680
Purchased power, non-affiliates		79,355			132,222			64,604
Purchased power, affiliates		64,587			195,743			135,336
Other operations and maintenance		136,655			147,711			134,971
Loss (gain) on sale of property		4,977			(6,015	)		—
Loss on IGCC project		—			—			17,619
Depreciation and amortization		98,135			88,511			73,985
Taxes other than income taxes		16,920			17,700			15,744
Total operating expenses		633,095			1,000,672			680,939
Operating Income		313,556			312,869			291,075
Other Income and (Expense):
Interest expense, net of amounts capitalized		(84,963	)		(83,212	)		(79,175	)
Profit recognized on construction contract		13,296			—			—
Other income (expense), net		(374	)		7,594			3,285
Total other income and (expense)		(72,041	)		(75,618	)		(75,890	)
Earnings Before Income Taxes		241,515			237,251			215,185
Income taxes		85,663			92,892			83,548
Net Income	$	155,852		$	144,359		$	131,637

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

II-407

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009, 2008, and 2007
Southern Power Company and Subsidiary Companies 2009 Annual Report

	2009			2008			2007
				(in thousands)
Operating Activities:
Net income	$	155,852		$	144,359		$	131,637
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		110,427			102,783			89,221
Deferred income taxes		22,950			70,338			31,665
Convertible investment tax credits received		16,800			—			—
Deferred revenues		2,288			(703	)		(4,852	)
Mark-to-market adjustments		5,204			(925	)		(3,033	)
Accumulated billings on construction contract		48,451			85,619			60,417
Accumulated costs on construction contract		(46,765	)		(110,096	)		(29,645	)
Loss on IGCC project		—			—			17,619
Profit recognized on construction contract		(13,296	)		—			—
Loss (gain) on sale of property		4,977			(6,015	)		—
Other, net		5,630			4,851			7,875
Changes in certain current assets and liabilities —
-Receivables		(9,717	)		(11,156	)		(3,155	)
-Fossil fuel stock		2,738			(2,640	)		(4,105	)
-Materials and supplies		(5,345	)		2,773			(1,169	)
-Prepaid income taxes		16,296			(21,338	)		—
-Other current assets		(298	)		1,413			(1,863	)
-Accounts payable		2,043			10,451			23,027
-Accrued taxes		88			(1,622	)		1,474
-Accrued interest		7			(252	)		319
-Other current liabilities		(199	)		(3,575	)		—
Net cash provided from operating activities		318,131			264,265			315,432
Investing Activities:
Property additions		(137,133	)		(49,964	)		(139,198	)
Cash paid for acquisitions		(194,156	)		—			—
Sale of property		84			5,073			—
Sale of property to affiliates		—			—			4,291
Change in construction payables, net		13,435			(7,529	)		(1,960	)
Payments pursuant to long-term service agreements		(46,120	)		(31,725	)		(44,471	)
Other investing activities		(184	)		(1,625	)		(2,514	)
Net cash used for investing activities		(364,074	)		(85,770	)		(183,852	)
Financing Activities:
Increase (decrease) in notes payable, net		118,948			(49,748	)		(74,004	)
Proceeds — Capital contributions		2,353			3,642			3,533
Redemptions — Other long-term debt		—			—			(1,209	)
Payment of common stock dividends		(106,100	)		(94,500	)		(89,800	)
Other		—			—			(24	)
Net cash provided from (used for) financing activities		15,201			(140,606	)		(161,504	)
Net Change in Cash and Cash Equivalents		(30,742	)		37,889			(29,924	)
Cash and Cash Equivalents at Beginning of Year		37,894			5			29,929
Cash and Cash Equivalents at End of Year	$	7,152		$	37,894		$	5
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,624, $7,075 and $16,541 capitalized, respectively)	$	73,064		$	69,716		$	63,766
Income taxes (net of refunds and investment tax credits)		30,220			47,611			50,724
Noncash value of business exchanged in West Georgia acquisition		70,839			—			—

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

II-408

CONSOLIDATED BALANCE SHEETS
At December 31, 2009 and 2008
Southern Power Company and Subsidiary Companies 2009 Annual Report

Assets	2009		2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	7,152	$	37,894
Receivables —
Customer accounts receivable		28,873		23,640
Other accounts receivable		2,064		2,162
Affiliated companies		38,561		33,401
Fossil fuel stock, at average cost		15,351		17,801
Materials and supplies, at average cost		31,607		26,527
Prepaid service agreements — current		44,090		26,304
Prepaid income taxes		5,177		18,066
Other prepaid expenses		3,176		2,756
Assets from risk management activities		4,901		10,799
Other current assets		6,754		4,532
Total current assets		187,706		203,882
Property, Plant, and Equipment:
In service		2,994,463		2,847,757
Less accumulated provision for depreciation		439,457		351,193
Plant in service, net of depreciation		2,555,006		2,496,564
Construction work in progress		153,982		8,775
Total property, plant, and equipment		2,708,988		2,505,339
Other Property and Investments:
Goodwill		1,794		—
Other intangible assets, net of amortization of $17		49,102		—
Total other property and investments		50,896		—
Deferred Charges and Other Assets:
Prepaid long-term service agreements		74,513		81,542
Other deferred charges and assets — affiliated		3,540		3,827
Other deferred charges and assets — non-affiliated		17,410		18,550
Total deferred charges and other assets		95,463		103,919
Total Assets	$	3,043,053	$	2,813,140

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

II-409

CONSOLIDATED BALANCE SHEETS
At December 31, 2009 and 2008
Southern Power Company and Subsidiary Companies 2009 Annual Report

Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Notes payable	$	118,948		$	—
Accounts payable —
Affiliated		58,493			62,732
Other		31,128			11,278
Accrued taxes —
Accrued income taxes		1,449			88
Other accrued taxes		2,576			2,343
Accrued interest		29,923			29,916
Liabilities from risk management activities		8,119			7,452
Billings in excess of cost on construction contract		297			11,907
Other current liabilities		26			224
Total current liabilities		250,959			125,940
Long-Term Debt:
Senior notes —
6.25% due 2012		575,000			575,000
4.875% due 2015		525,000			525,000
6.375% due 2036		200,000			200,000
Unamortized debt discount		(2,393	)		(2,647	)
Long-term debt		1,297,607			1,297,353
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		238,293			209,960
Deferred convertible investment tax credits		16,800			—
Deferred capacity revenues — affiliated		36,369			32,211
Other deferred credits and liabilities — affiliated		5,651			6,667
Other deferred credits and liabilities — non-affiliated		2,252			2,648
Total deferred credits and other liabilities		299,365			251,486
Total Liabilities		1,847,931			1,674,779
Common Stockholder’s Equity:
Common stock, par value $0.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		864,462			862,109
Retained earnings		352,061			302,309
Accumulated other comprehensive income (loss)		(21,401	)		(26,057	)
Total common stockholder’s equity		1,195,122			1,138,361
Total Liabilities and Stockholder’s Equity	$	3,043,053		$	2,813,140
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 31,2009, 2008, and 2007
Southern Power Company and Subsidiary Companies 2009 Annual Report

	Number of										Accumulated
	Common										Other
	Shares		Common			Paid-In		Retained			Comprehensive
	Issued		Stock			Capital		Earnings			Income (Loss)			Total
					(in thousands)
Balance at December 31, 2006		1	$	—		$	854,933	$	211,295		$	(40,724	)	$	1,025,504
Net income		—		—			—		131,637			—			131,637
Capital contributions from parent company		—		—			3,533		—			—			3,533
Other comprehensive income (loss)		—		—			—		—			7,014			7,014
Cash dividends on common stock		—		—			—		(89,800	)		—			(89,800	)
Other		—		—			—		(1	)		—			(1	)
Balance at December 31, 2007		1		—			858,466		253,131			(33,710	)		1,077,887
Net income		—		—			—		144,359			—			144,359
Capital contributions from parent company		—		—			3,643		—			—			3,643
Other comprehensive income (loss)		—		—			—		—			7,653			7,653
Cash dividends on common stock		—		—			—		(94,500	)		—			(94,500	)
Other		—		—			—		(681	)		—			(681	)
Balance at December 31, 2008		1		—			862,109		302,309			(26,057	)		1,138,361
Net income		—		—			—		155,852			—			155,852
Capital contributions from parent company		—		—			2,353		—			—			2,353
Other comprehensive income (loss)		—		—			—		—			4,656			4,656
Cash dividends on common stock		—		—			—		(106,100	)		—			(106,100	)
Balance at December 31, 2009		1	$	—		$	864,462	$	352,061		$	(21,401	)	$	1,195,122

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2009,2008, and 2007
Southern Power Company and Subsidiary Companies 2009 Annual Report

	2009			2008		2007
				(in thousands)
Net income	$	155,852		$	144,359	$	131,637
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(664), $351, and $(558), respectively		(1,044	)		529		(842	)
Reclassification adjustment for amounts included in net income, net of tax of $3,875, $4,554, and $5,244, respectively		5,700			7,124		7,856
Total other comprehensive income (loss)		4,656			7,653		7,014
Comprehensive Income	$	160,508		$	152,012	$	138,651

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

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NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2009 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 four traditional operating companies, Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies, Alabama Power Company (APC), Georgia Power Company (GPC), Gulf Power Company (Gulf Power), and Mississippi Power Company, are vertically integrated utilities providing electric service in four Southeastern states. The Company constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

The Company is subject to regulation by the Federal Energy Regulatory Commission (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. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

The financial statements include the accounts of the Company and its wholly-owned subsidiaries, Southern Company — Florida LLC, Oleander Power Project, LP (Oleander), Southern Power Company — Orlando Gasification LLC (SPC-OG), and Nacogdoches Power LLC, which own, operate, and maintain the Company’s ownership interests in Plant Stanton Unit A and Plant Oleander, construct the combined cycle for the Orlando Utilities Commission (OUC), and construct a biomass generating facility, respectively. See Note 2 under “Nacogdoches Power LLC Acquisition.” 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 amounts in compliance with FERC regulation: 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, digital wireless communications, labor, and other services with respect to business and operations and Southern Company system fleet of generating units (power pool) transactions. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for these services from SCS amounted to approximately $133.0 million in 2009, $207.4 million in 2008, and $125.4 million in 2007. Approximately $83.1 million in 2009, $87.9 million in 2008, and $74.1 million in 2007 were operations and maintenance expenses; the remainder was recorded to construction work in progress, other assets, and billings in excess of cost on construction contract. Cost allocation methodologies used by SCS were approved by the Securities and Exchange Commission prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

In 2003, the Company entered into agreements with APC and GPC under which APC and GPC operated and maintained Plants Dahlberg, Wansley, Franklin, and Harris. GPC also supplied various services for other plants. In August 2007, those agreements were terminated and replaced with service agreements under which APC and GPC provide specifically requested services to the Company. These services are billed at amounts in compliance with FERC regulation on a monthly basis and are recorded as operations and maintenance expenses in the consolidated statements of income. For the periods ended December 31, 2009, 2008, and 2007, billings under these agreements totaled approximately $1.4 million, $2.9 million, and $9.2 million, respectively.

Total billings for all purchased power agreements (PPAs) in effect with affiliates totaled $485.1 million, $539.6 million, and $505.2 million in 2009, 2008, and 2007, respectively. Included in these billings were $36.4 million and $32.2 million of “Deferred capacity revenues — affiliated” recorded on the balance sheets at December 31, 2009 and 2008, respectively. The Company and the traditional 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.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

The Company and the traditional operating companies 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.

In 2009, there were no material transactions involving the sale of property to affiliated companies.

In 2008, Gulf Power and APC sold turbine rotor assemblies to the Company for $9.4 million and $6.3 million, respectively. Additionally, the Company sold a turbine rotor assembly to APC for $8.2 million and sold a compressor assembly to GPC for $3.9 million. No gain or loss was recognized in the Company’s consolidated statements of income. These affiliate transactions were made in accordance with FERC and state Public Service Commission (PSC) rules and guidelines.

In 2007, the Company sold plots of land in Prattville, Alabama and Chilton County, Alabama to APC. The total sales price was $4.3 million and is recorded in “Sale of property to affiliates” on the consolidated statements of cash flows. In addition, the Company sold a turbine rotor to Gulf Power for $7.9 million. No gain or loss was recognized in the Company’s consolidated statements of income. These affiliate transactions were made in accordance with FERC and state PSC rules and guidelines.

Acquisition Accounting

The Company has been engaged in a strategy of acquiring assets. The Company has accounted for these acquisitions under the purchase method in accordance with generally accepted accounting principles (GAAP). Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price of each acquisition was allocated to the fair value of the identifiable assets and liabilities. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions after December 31, 2008 have been expensed as incurred.

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. Transmission revenues and other fees are recognized as incurred as other operating revenue. Revenues are recorded on a gross basis for all full requirements PPAs. See “Financial Instruments” for additional information.

Significant portions of the Company’s revenues have been derived from certain customers pursuant to PPAs. For the year ended December 31, 2009, GPC accounted for 43.7% of total revenues, APC accounted for 6.6% of total revenues, and Sawnee Electric Membership Corporation accounted for 6.0% of total revenues. For the year ended December 31, 2008, GPC accounted for 36.5% of total revenues, Sawnee Electric Membership Corporation accounted for 6.1% of total revenues, and Flint Electric Membership Corporation accounted for 5.3% of total revenues. For the year ended December 31, 2007, GPC accounted for 45.6% of total revenues, APC accounted for 6.9% of total revenues, and Sawnee Electric Membership Corporation accounted for 5.5% of total revenues.

Fuel Costs

Fuel costs are expensed as the fuel is consumed. Fuel costs also include emissions allowances which are expensed as the emissions occur.

Income and Other 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. In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 5 under “Unrecognized Tax Benefits” for additional information.

Convertible Investment Tax Credits

Under the American Recovery and Reinvestment Act of 2009, certain costs related to the Nacogdoches plant construction are eligible for investment tax credits (ITCs) or cash grants. The Company has elected to receive ITCs. The credits are recorded as a deferred credit, which will be amortized over the life of the asset, and the tax basis

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

of the asset is reduced by 50% of the credits received, resulting in a deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. This basis difference will reverse and be recorded to income tax expense over the useful life of the asset once placed in service. The credits received during the year will be shown within operating activities in the consolidated statements of cash flows.

Property, Plant, and Equipment

The Company’s depreciable property, plant, and equipment consists entirely of generation assets.

Property, plant, and equipment is stated at original cost. Original cost includes materials, direct labor incurred by contractors and 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.

Depreciation

Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate 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 composite depreciable life ranging from 24-35 years. These lives reflect a composite of the significant components (retirement units) that make up the plants. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.

A depreciation study was completed and the applicable remaining plant lives and associated depreciation rates were revised in January 2008 and January 2009. This change in estimate was due to revised useful life assumptions for certain components of plant in service. Depreciation rates by generating facility changed from a range of 2.8% to 3.8% to an adjusted range of 1.8% to 4.1% in January 2008. Depreciation rates by generating facility changed to an adjusted range of 1.9% to 5.6% in January 2009. These changes increased depreciation and reduced income from continuing operations and net income by $4.6 million and $2.8 million, respectively, for 2008 and $5.1 million and $3.1 million, respectively, for 2009.

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, 2009, the Company had no material liability for asset retirement obligations.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets and intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company’s intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of the PPAs is 20 years. 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 impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. Impairment of goodwill is assessed on an annual basis. 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.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

The amortization expense for the PPAs is as follows:

	Amortization
	Expense
	(in millions)
2010	$	0.7
2011		0.8
2012		1.8
2013		2.5
2014		2.5
2015 and beyond		40.9
Total	$	49.2

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 $9.0 million at December 31, 2009, $8.9 million at December 31, 2008, and $8.4 million at December 31, 2007.

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 generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

Fuel inventory includes the cost of oil and emissions allowances. The Company maintains minimal oil levels for use at Plant Dahlberg, Plant Oleander, Plant Rowan, and Plant West Georgia. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost 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 (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 8 for additional information. Substantially all of the Company’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify and are designated for the “normal” scope exception, and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2009.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

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 fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). See Note 8 for all other items recognized at fair value in the financial statements.

Other Income and (Expense)

Other income and (expense) includes non-operating revenues and expenses. Revenues are recognized when earned and expenses are recognized when incurred.

The Company has a long-term contract for engineering, procurement, and construction services to build a combined cycle unit for the OUC. Construction activities commenced in 2006 and were substantially completed in 2009. Billings and costs are recognized using the percentage of completion method. The Company utilizes the cost-to-cost approach as this method is less subjective than relying on assessments of physical progress. The percentage of completion represents the percentage of the total costs incurred to the estimated total cost of the contract. Billings and costs are recognized on a net basis by applying this percentage to the total revenues and estimated costs of the contract and are recorded in other income and (expense) in the consolidated statements of income. Net profit recognized under the long-term construction contract for the OUC was $13.3 million in 2009. No profit or loss was recognized in 2008 or 2007.

In 2008, the Company received a fee of $6.4 million for participating in an asset auction. The Company was not the successful bidder in the asset auction.

Interest related to the construction of new facilities is capitalized in accordance with GAAP.

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 reclassifications of amounts included in net income.

2. ACQUISITIONS AND DIVESTITURES

Nacogdoches Power LLC Acquisition

On October 8, 2009, the Company acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. The Company is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 megawatts (MWs). The generating plant will be fueled from wood waste. Construction commenced in late 2009 and the plant is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032 or until a contractual limit of $2.3 billion is reached. This PPA will be accounted for as an operating lease.

The Company’s acquisition of the interests in Nacogdoches included cash consideration of approximately $50.1 million. The Nacogdoches acquisition is in accordance with the Company’s overall growth strategy. There are no contingent consideration arrangements and no significant assets or liabilities arising from contingencies. No goodwill was recorded as a result of this acquisition. An intangible asset related to the assumed PPA with Austin Energy was recognized. Due diligence and transition costs for Nacogdoches were expensed as incurred and were not material. The fair value of the consideration transferred and the fair value of each major class of assets and liabilities at the acquisition date was as follows:

As of October 8, 2009
	(in millions)
Construction work in progress	$	16.2
Other assets		0.1
Intangible assets		33.8
Total fair value of the membership interests in Nacogdoches	$	50.1

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture

On December 17, 2009, the Company acquired all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC (Broadway), an affiliate of LS Power. West Georgia was merged into the Company and the Company now owns a 669-MW nameplate capacity generating facility consisting of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with the Municipal Electric Authority of Georgia (MEAG Power) and the Georgia Energy Cooperative, Inc. (GEC). The MEAG Power agreement began in 2009 and expires in 2029. The GEC agreement begins in 2010 and expires in 2030.

The Company’s acquisition of the interests in West Georgia was pursuant to an agreement which included the transfer of all the outstanding membership interests of DeSoto County Generating Company LLC (DeSoto) from the Company to Broadway and the payment by the Company of $144.0 million in cash consideration. The carrying values of the major classes of assets disposed of were $2.0 million in fossil fuel stock, $1.2 million in materials and supplies, $72.1 million in property, plant and equipment, and $0.8 million in other deferred assets. The transaction was treated as a like-kind exchange for income tax purposes. The West Georgia acquisition is in accordance with the Company’s overall growth strategy. There are no contingent consideration arrangements and no significant assets or liabilities arising from contingencies. The goodwill arising from the acquisition consists largely of synergies and economies of scale from combining the operations of the Company and West Georgia and is expected to be tax deductible. Due diligence and transition costs for West Georgia were expensed as incurred and were not material.

The fair value of the consideration transferred and the fair value of each major class of assets and liabilities at the acquisition date was as follows:

As of December 17, 2009
	(in millions)
Customer accounts receivable	$	0.4
Fossil fuel stock		1.8
Materials and supplies		0.9
Property, plant, and equipment		192.4
Other assets		2.5
Goodwill		1.8
Intangible assets (PPAs)		15.3
Accounts payable		(0.3	)
Total fair value of the membership interests in West Georgia		214.8
Fair value of DeSoto interests		(70.8	)
Cash consideration transferred	$	144.0

Fair value amounts allocated to materials and supplies and other assets are preliminary estimates pending final application of the Company’s accounting policies.

Revenues and expenses recognized by the Company for West Georgia operations after the closing date were not material. PPA amortization expense for 2009 was not material.

Pro Forma Information

The following unaudited pro forma financial information gives effect to the Nacogdoches acquisition, the West Georgia acquisition, and the DeSoto divestiture as if they had occurred as of the beginning of the periods presented. The pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the Company that would have been reported had the acquisitions and divestiture been completed as of the dates presented nor should the information be taken as representative of any future consolidated results of operations or financial condition of the Company.

For the Twelve Months Ended December 31
	2009		2008
	(in millions)
Pro forma revenues	$	957.4	$	1,353.3
Pro forma net income		151.1		146.6

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 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 and other damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the 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 the Company’s financial statements.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. 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 market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that the Company possessed or has exercised any market power. The agreement likewise does not require the Company to make any refunds related to sales during the 15-month refund period. Under the agreement, the Company will donate $0.2 million to nonprofit organizations in the States of Alabama and Georgia for the purpose of offsetting the electricity bills of low-income retail customers. The agreement is subject to review and approval by the FERC.

Intercompany Interchange Contract

The majority of the Company’s generation fleet is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, the Company, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, (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.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of the Company. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on the Company’s financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Carbon Dioxide Litigation

Kivalina Case

In February, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. District Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. The Company is not currently a party to this litigation but was named as a defendant in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

4. JOINT OWNERSHIP AGREEMENTS

The Company is a 65% owner of Plant Stanton A, a combined-cycle project with a nameplate capacity of 630 MWs. The unit is co-owned by the OUC (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2009, $151.2 million was recorded in plant in service with associated accumulated depreciation of $19.8 million. These amounts represent the Company’s share of the total plant assets and each owner must provide its own financing. The Company’s proportionate share of Plant Stanton A’s operating expense 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 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 it filed a separate income tax return. In accordance with Internal Revenue Service (IRS) regulations, each company is jointly and severally liable for the tax liability.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2009		2008		2007
	(in millions)
Federal —
Current	$	55.0	$	18.9	$	42.8
Deferred		19.3		57.2		26.8
		74.3		76.1		69.6
State —
Current		7.7		3.6		9.0
Deferred		3.7		13.2		4.9
		11.4		16.8		13.9
Total	$	85.7	$	92.9	$	83.5

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:

	2009			2008
	(in millions)
Deferred tax liabilities—
Accelerated depreciation and other property basis differences	$	303.9		$	274.1
Basis difference on asset transfers		3.9			4.3
Other		—			2.5
Total		307.8			280.9
Deferred tax assets—
Federal effect of state deferred taxes		13.7			12.9
Basis difference on convertible investment tax credits		2.9			—
Basis differences on asset transfers		6.7			7.9
Other comprehensive loss on interest rate swaps		28.1			32.4
Levelized capacity revenues		15.2			14.3
Other		1.7			—
Total		68.3			67.5
Total deferred tax liabilities, net		239.5			213.4
Portion included in current income taxes		(1.2	)		(3.4	)
Accumulated deferred income taxes in the balance sheets	$	238.3		$	210.0

Deferred tax liabilities are the result of property related timing differences. The transfer of the Plant McIntosh construction project to GPC in 2004 resulted in a deferred gain for federal income tax purposes. GPC is reimbursing the Company for the related tax liability balance of $3.9 million. Of this total, $0.4 million is included in the balance sheets in “Receivables — Affiliated companies” and the remainder is included in “Other deferred charges and assets — affiliated.”

Deferred tax assets consist primarily of timing differences related to the recognition of capacity revenues and the deferred loss on interest rate swaps reflected in other comprehensive income. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from GPC in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse GPC for the related tax asset of $6.7 million. Of this total, $1.0 million is included in the balance sheets in “Accounts payable — Affiliated” and the remainder is included in “Other deferred credits and liabilities — affiliated.”

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Effective Tax Rate

A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:

	2009			2008			2007
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		3.1			4.6			4.2
ITC basis difference		(1.2	)		—			—
Other		(1.4	)		(0.4	)		(0.4	)
Effective income tax rate		35.5	%		39.2	%		38.8	%

The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable to U.S. production activities as defined in the Internal Revenue Code of 1986, as amended, Section 199 (production activities deduction). The deduction is equal to a stated percentage of qualified production activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company reached an agreement with the IRS on a calculation methodology and signed a closing agreement in December 2008. Therefore, in 2008, the Company reversed the unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when compared to the 2007 deduction. Certain aspects of the production activities deduction remain unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the application of the new methodology had no material effect on the Company’s financial statements.

Convertible ITCs received in 2009 for the construction of Plant Nacogdoches were $16.8 million; the tax benefit of the basis difference reduced income tax expense by $2.9 million. See Note 1 under “Summary of Significant Accounting Policies — Convertible Investment Tax Credits” for additional information.

Unrecognized Tax Benefits

For 2009, the total amount of unrecognized tax benefits decreased $0.4 million, resulting in a balance of $0.1 million as of December 31, 2009.

Changes during the year in unrecognized tax benefits were as follows:

	2009			2008			2007
				(in millions)
Unrecognized tax benefits at beginning of year	$	0.5		$	1.4		$	0.2
Tax positions from current periods		0.3			0.3			0.4
Tax positions from prior periods		(0.7	)		0.1			0.8
Reductions due to settlements		—			(1.3	)		—
Reductions due to expired statute of limitations		—			—			—
Balance at end of year	$	0.1		$	0.5		$	1.4

The tax positions from the current periods increase for 2009 relate primarily to the production activities deduction tax position and other miscellaneous uncertain tax positions. The tax positions decrease from prior periods for 2009 relates primarily to the production activities deduction tax position. See “Effective Tax Rate” above for additional information.

Impact on the Company’s effective tax rate, if recognized, is as follows:

	2009		2008		2007
	(in millions)
Tax positions impacting the effective tax rate	$	0.1	$	0.5	$	1.4
Tax positions not impacting the effective tax rate		—		—		—
Balance of unrecognized tax benefits	$	0.1	$	0.5	$	1.4

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Accrued interest for unrecognized tax benefits was as follows:

	2009		2008			2007
	(in millions)
Interest accrued at beginning of year	$	—	$	0.1		$	—
Interest reclassified due to settlements		—		(0.1	)		—
Interest accrued during the year		—		—			0.1
Balance at end of year	$	—	$	—		$	0.1

The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of the Company’s unrecognized tax positions will increase or decrease within the next 12 months. The possible conclusion or settlement of state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns have either been concluded, or the statute of limitations has expired, for years prior to 2006.

6. FINANCING

Senior Notes

In 2009 and 2008, the Company did not issue any long-term debt securities. Long-term debt outstanding was $1.3 billion at December 31, 2009 and 2008.

Bank Credit Arrangements

The Company has a $400 million unsecured syndicated revolving credit facility (Facility) expiring in July 2012. The purpose of the Facility is to provide liquidity support to the Company’s commercial paper program and for other general corporate purposes. There were no borrowings outstanding under the Facility at December 31, 2009 and 2008.

The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than¹/₈ of 1%. In 2009 and 2008, the Company incurred approximately $0.4 million and $0.4 million, respectively, in expenses from commitment fees under the Facility.

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. 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, 2009, the Company was in compliance with all such covenants.

The Company has established a commercial paper program. For the year ended December 31, 2009, the peak commercial paper balance outstanding was $118.9 million. The average amount outstanding was $6.6 million in 2009. The average annual interest rate was 0.4%. At December 31, 2009, the commercial paper program had $118.9 million outstanding. At December 31, 2008, the commercial paper program had no outstanding balances.

Dividend Restrictions

The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

The Facility and the indenture related to certain series of the Company’s senior notes also contain 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 are at least 80% of total projected cash flows for the next 12 months or the Company’s debt to capitalization ratio is no greater than 60%. At December 31, 2009, the Company was in compliance with these ratios and had no other restrictions on its ability to pay dividends.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

7. COMMITMENTS

Expansion Program

The capital program of the Company is currently estimated to be $627.4 million for 2010, $856.5 million for 2011, and $379.0 million for 2012. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and the Company’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Long-Term Service Agreements

The Company has entered into Long-Term Service Agreements (LTSAs) with General Electric and Siemens AG for the purpose of securing maintenance support for its combined cycle and combustion turbine generating facilities. In summary, the LTSAs provide that the vendors will perform all planned inspections and certain unplanned maintenance on the covered equipment, which includes the cost of all labor and materials.

Scheduled payments to the vendors, which are subject to price escalation, are made at various intervals based on actual operating hours or number of gas turbine starts of the respective units. Total remaining payments to the vendors under these agreements are currently estimated at $1.2 billion over the remaining term of the agreements, which may range up to 24 years. However, the LTSAs contain various cancellation provisions at the Company’s and the applicable vendor’s option. In the event of cancellation prior to scheduled work being performed, the Company is entitled to a refund of amounts paid as calculated in accordance with termination provisions of the agreements.

Payments made to the vendors prior to the performance of any planned inspections or unplanned maintenance are recorded as a prepayment in current assets or deferred charges and other assets on the balance sheets and are recorded as payments pursuant to long-term service agreements in the statements of cash flows. Inspection and maintenance costs are capitalized or charged to expense based on the nature of the work when performed and are non-cash and are not reflected in the statements of cash flows.

Fuel and Purchased Power Commitments

SCS, as agent for the traditional operating companies and the Company, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities. In most cases, these contracts contain provisions for firm transportation costs, storage costs, minimum purchase levels, and other financial commitments. Natural gas purchase commitments contain fixed 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, 2009. Also, the Company has entered into various long-term commitments for the purchase of biomass fuel for the biomass generating plant being constructed by the Company and for the purchase of electricity.

Total estimated minimum long-term obligations at December 31, 2009 were as follows:

	Natural Gas		Biomass Fuel		Purchased Power
	Commitments		Commitments		Commitments(a)
			(in millions)
2010	$	165.8	$	—	$	13.6
2011		182.4		—		7.8
2012		141.5		17.0		49.2
2013		129.6		17.4		50.4
2014		109.9		17.7		51.6
2015 and beyond		277.6		127.6		295.2
Total	$	1,006.8	$	179.7	$	467.8

(a) Represents contractual capacity payments.

Additional commitments for fuel will be required to supply the Company’s future needs.

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Notes (continued)
Southern Power Company and Subsidary Companies 2009 Annual Report

During 2008, the Company entered into agreements to purchase 452 MWs of power from three counterparties. Approximately 352 MWs of these commitment obligations will be used to serve the Company’s requirements service customers. Another power purchase agreement for 100 MWs will be resold to EnergyUnited Electric Membership Corporation (EnergyUnited) at cost for the period 2012 through 2021. The purchase power commitments for the EnergyUnited agreement are $35.4 million in 2012, $36.1 million in 2013, $36.8 million in 2014, and $279.3 million in 2015 and beyond.

In addition, the Company has entered into an agreement to purchase power of up to 200 MWs at the discretion of the counterparty for the period 2011 through 2018. There is no contractual capacity payment required under this agreement. Additionally, for all amounts purchased under this arrangement, the Company will pay the counterparty an amount per MW which approximates the Company’s cost.

Acting as an agent for all of Southern Company’s traditional operating companies and the Company, SCS may enter into various types of wholesale energy and natural gas contracts. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. The creditworthiness of the Company is currently inferior to the creditworthiness of the traditional operating companies; therefore, Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize nor be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company 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 $0.5 million, $0.5 million, and $0.5 million for 2009, 2008, and 2007, respectively. The majority of the lease expense amounts and committed future expenditures are with a joint owner of Plant Stanton Unit A.

At December 31, 2009, estimated minimum rental commitments for noncancelable operating leases were as follows:

	Operating Lease
	Commitments
	(in millions)
2010	$	0.6
2011		0.5
2012		0.5
2013		0.5
2014		0.5
2015 and beyond		22.3
Total	$	24.9

8. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company’s own assumptions are the best available information. The need to use unobservable inputs would typically apply to long-term energy-related derivative contracts and generally results from the nature of the energy industry, as each participant forecasts its own power supply and demand and those of other participants, which directly impact the valuation of each unique contract.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

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Notes (continued)
Southern Power Company and Subsidary Companies 2009 Annual Report

The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at December 31, 2009 are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of December 31, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Energy-related derivatives	$	—	$	5.1	$	—	$	5.1
Liabilities:
Energy-related derivatives	$	—	$	8.6	$	—	$	8.6

Energy-related derivatives primarily consist of over-the-counter contracts. See Note 9 for additional information. All of these financial instruments are valued primarily using the market approach.

As of December 31, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2009	$	1,298	$	1,379
2008		1,297		1,270

9. DERIVATIVES

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 its exposures, where possible, 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. The Company’s 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for in one of two methods:

• Cash Flow Hedges– Gains and losses on energy-related derivatives designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income (OCI) before being recognized in income in the same period as the hedged transactions are reflected in earnings.

• Not Designated– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At December 31, 2009, the net volume of energy-related derivative contracts for power and natural gas positions for the Company, together with the longest hedge date over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

Power					Gas
Net Sold	Longest		Longest		Net			Longest		Longest
Megawatt-	Hedge		Non-Hedge		Purchased			Hedge		Non-Hedge
hours	Date		Date		mmBtu			Date		Date
(in millions)					(in millions)
2.6		2010		2010		11	*		2012		2014

* Includes location basis of 2 million British thermal units (mmBtu).

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending December 31, 2010 are losses of $1.1 million and $1.0 million, respectively.

Interest Rate Derivatives

The Company also enters into interest rate derivatives from time to time, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges, where the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2009, there were no interest rate derivatives outstanding.

The estimated pre-tax loss that will be reclassified from OCI to interest expense for the next 12-month period ending December 31, 2010 is $10.7 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2016.

Derivative Financial Statement Presentation and Amounts

At December 31, 2009 and 2008, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

	Asset Derivatives					Liability Derivatives
Derivative Category	Balance Sheet Location	2009		2008		Balance Sheet Location	2009		2008
		(in millions)					(in millions)
Derivatives designated as hedging instruments in cash flow hedges
Energy-related derivatives:	Assets from risk management activities	$	3.2	$	—	Liabilities from risk management activities	$	5.3	$	0.6
	Other deferred charges and assets — non-affiliated		—		—	Other deferred credits and liabilities — non-affiliated		0.4		0.2
Total derivatives designated as hedging instruments in cash flow hedges		$	3.2	$	—		$	5.7	$	0.8
Derivatives not designated as hedging instruments
Energy-related derivatives:	Assets from risk management activities	$	1.7	$	10.8	Liabilities from risk management activities	$	2.8	$	6.9
	Other deferred charges and assets — non-affiliated		0.2		0.3	Other deferred credits and liabilities — non-affiliated		0.1		—
Total derivatives not designated as hedging instruments		$	1.9	$	11.1		$	2.9	$	6.9
Total		$	5.1	$	11.1		$	8.6	$	7.7

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

All derivative instruments are measured at fair value. See Note 8 for additional information.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss) Recognized in								Gain (Loss) Reclassified from Accumulated OCI into Income
Derivatives in Cash Flow	OCI on Derivative								(Effective Portion)
Hedging Relationships	(Effective Portion)									Amount
Derivative Category	2009			2008		2007			Statements of IncomeLocation	2009			2008			2007
				(in millions)									(in millions)
Energy-related derivatives	$	(1.7	)	$	0.9	$	(1.4	)	Fuel	$	—		$	—		$	(0.1	)
									Amortization and Depreciation		0.4			0.4			0.4
Interest rate derivatives		—			—		—		Interest expense		(10.0	)		(12.0	)		(13.4	)
Total	$	(1.7	)	$	0.9	$	(1.4	)		$	(9.6	)	$	(11.6	)	$	(13.1	)

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated	Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments		Amount
Derivative Category	Statements of Income Location		2009		2008			2007
		(in millions)
Energy-related derivatives:	Wholesale revenues	$	5.3		$	(1.9	)	$	—
	Fuel		(6.0	)		5.1			—
	Purchased power		(4.5	)		(2.3	)		—
	Other income (expense), net		—			—			2.8
Total		$	(5.2	)	$	0.9		$	2.8

Contingent Features

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 derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2009, the fair value of derivative liabilities with contingent features was $1.7 million.

At December 31, 2009, the Company had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $33.3 million.

Currently, the Company has investment grade credit ratings from the major rating agencies with respect to debt.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade.

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NOTES (continued)
Southern Power Company and Subsidiary Companies 2009 Annual Report

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2009 and 2008 is as follows:

	Operating		Operating		Net
Quarter Ended	Revenues		Income		Income
			(in thousands)
March 2009	$	231,517	$	66,981	$	27,916
June 2009		230,598		73,276		31,054
September 2009		283,369		127,165		67,280
December 2009		201,168		46,134		29,602
March 2008	$	215,532	$	52,661	$	28,975
June 2008		316,584		79,732		35,420
September 2008		515,871		118,592		59,562
December 2008		265,554		61,884		20,402

The Company’s business is influenced by seasonal weather conditions. Fourth quarter 2009 net income includes profit recognized on the OUC construction contract of $10.6 million pretax and $6.5 million after tax.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2005-2009
Southern Power Company and Subsidiary Companies 2009 Annual Report

	2009		2008		2007		2006		2005
Operating Revenues (in thousands):
Wholesale — non-affiliates	$	394,366	$	667,979	$	416,648	$	279,384	$	223,058
Wholesale — affiliates		544,415		638,266		547,229		491,762		556,664
Total revenues from sales of electricity		938,781		1,306,245		963,877		771,146		779,722
Other revenues		7,870		7,296		8,137		5,902		1,282
Total	$	946,651	$	1,313,541	$	972,014	$	777,048	$	781,004
Net Income (in thousands)	$	155,852	$	144,359	$	131,637	$	124,469	$	114,791
Cash Dividends on Common Stock (in thousands)	$	106,100	$	94,500	$	89,800	$	77,700	$	72,400
Return on Average Common Equity (percent)		13.36		13.03		12.52		13.16		13.68
Total Assets (in thousands)	$	3,043,053	$	2,813,140	$	2,768,774	$	2,690,943	$	2,302,976
Gross Property Additions/Plant Acquisitions (in thousands)	$	331,289	$	49,964	$	139,198	$	465,026	$	241,103
Capitalization (in thousands):
Common stock equity	$	1,195,122	$	1,138,361	$	1,077,887	$	1,025,504	$	866,343
Long-term debt		1,297,607		1,297,353		1,297,099		1,296,845		1,099,520
Total (excluding amounts due within one year)	$	2,492,729	$	2,435,714	$	2,374,986	$	2,322,349	$	1,965,863
Capitalization Ratios (percent):
Common stock equity		47.9		46.7		45.4		44.2		44.1
Long-term debt		52.1		53.3		54.6		55.8		55.9
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		Baa1
Standard and Poor’s	BBB+		BBB+		BBB+		BBB+		BBB+
Fitch	BBB+		BBB+		BBB+		BBB+		BBB+
Kilowatt-Hour Sales (in thousands):
Wholesale — non-affiliates		7,513,569		7,573,713		6,985,592		5,093,527		3,932,638
Wholesale — affiliates		12,293,585		9,402,020		10,766,003		8,493,441		6,355,249
Total		19,807,154		16,975,733		17,751,595		13,586,968		10,287,887
Average Revenue Per Kilowatt-Hour (cents)		4.74		7.69		5.43		5.68		7.58
Plant Nameplate Capacity Ratings (year-end) (megawatts)		7,880		7,555		6,896		6,733		5,403
Maximum Peak-Hour Demand (megawatts):
Winter		3,224		3,042		2,815		2,780		2,037
Summer		3,308		3,538		3,717		2,869		2,420
Annual Load Factor (percent)		52.6		50.0		48.2		53.6		48.9
Plant Availability (percent)		96.7		96.0		96.7		98.3		97.6
Source of Energy Supply (percent):
Gas		84.4		75.6		70.4		68.3		72.6
Purchased power —
From non-affiliates		7.9		11.3		8.8		9.6		9.6
From affiliates		7.7		13.1		20.8		22.1		17.8
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 on page III-41), 13, and 14 for Southern Company are incorporated by reference to Southern Company’s Definitive Proxy Statement relating to the 2010 Annual Meeting of Stockholders. Specifically, reference is made to “Nominees for Election as Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation,” “Compensation Discussion and Analysis,” “Compensation and Management Succession Committee Report,” “Director Compensation,” and “Director Compensation Table” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” and “Director Independence” for Item 13, and “Principal Public Accounting Firm Fees” for Item 14.

Items 10, 11, 12, 13, and 14 for Alabama Power, Georgia Power, and Mississippi Power are incorporated by reference to the Definitive Information Statements of Alabama Power, Georgia Power, and Mississippi Power relating to each of their respective 2010 Annual Meetings of Shareholders. Specifically, reference is made to “Nominees for Election as Directors,” “Corporate Governance,” and “Section 16(a) Beneficial Ownership Reporting Compliance” for Item 10, “Executive Compensation Information,” “Compensation Discussion and Analysis,” “Compensation and Management Succession Committee Report,” “Director Compensation,” and “Director Compensation Table” for Item 11, “Stock Ownership Table” for Item 12, “Certain Relationships and Related Transactions” and “Director Independence” for Item 13, and “Principal Public Accounting Firm Fees” for Item 14.

Items 10, 11, 12, 13, and 14 for Gulf Power are contained herein.

Items 10, 11, 12 and 13 for Southern Power are omitted pursuant to General Instruction I(2)(c) of Form 10-K. Item 14 for Southern Power is contained herein.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Identification of directors of Gulf Power.

Susan N. Story	Fred C. Donovan, Sr.(1)
President and Chief Executive Officer	Age 69
Age 49	Served as Director since 1991
Served as Director since 2003
C. LeDon Anchors(1)	William A. Pullum(1)
Age 69	Age 62
Served as Director since 2001	Served as Director since 2001
William C. Cramer, Jr.(1)	Winston E. Scott(1)
Age 57	Age 59
Served as Director since 2002	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 (June 30, 2009) 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, other than any arrangements or understandings with directors or officers of Gulf Power acting solely in their capacities as such.

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Identification of executive officers of Gulf Power.

Susan N. Story	Theodore J. McCullough
President and Chief Executive Officer	Vice President — Senior Production Officer
Age 49	Age 46
Served as Executive Officer since 2003	Served as Executive Officer since 2007
P. Bernard Jacob	Bentina C. Terry
Vice President — Customer Operations	Vice President — External Affairs and Corporate Services
Age 55	Age 39
Served as Executive Officer since 2003	Served as Executive Officer since 2007
Philip C. Raymond
Vice President and Chief Financial Officer
Age 50
Served as Executive Officer since 2008

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 23, 2009) for one year until the next annual organizational 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 directors or 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.

DIRECTORS

Gulf Power’s Board of Directors possesses collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and Gulf Power’s industry.

Susan N. Story- President and Chief Executive Officer of Gulf Power. Ms. Story has previously served in leadership roles in a number of areas, including engineering and construction, supply chain, real estate and corporate services with affiliated subsidiaries. Currently, Ms. Story also serves on the Board of Directors of Raymond James Financial, Inc.

C. LeDon Anchors- Attorney and President of Anchors Smith Grimsley, Attorneys at Law, Fort Walton Beach, Florida. As an attorney, Mr. Anchors areas of practice include real estate, family law, banking, business law, commercial law, corporate law, government, and probate. He is also a director of Beach Community Bank, Fort Walton Beach, Florida, where he serves on the audit committee and the assets and liabilities committee. Mr. Anchors has also served in leadership roles at a number of civic organizations.

William C. Cramer, Jr.- President and Owner of automobile dealerships in Florida, Georgia, and Alabama. Mr. Cramer has been an authorized Chevrolet dealer since 1978. In 2009, Mr Cramer became an authorized dealer of Cadillac, Buick, and GMC vehicles.

Fred C. Donovan, Sr.- Chairman and Chief Executive Officer of Baskerville-Donovan, Inc. (an architectural and engineering firm), Pensacola, Florida. Mr. Donovan is responsible for establishing the strategic direction and providing the overall management of the firm. He also serves as Chairman of the Baptist Healthcare Board of Directors. Previously, he has served in leadership roles with Chambers of Commerce in his area.

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William A. Pullum- President and Director of Bill Pullum Realty, Inc., Navarre, Florida. Mr. Pullum is also a real estate developer.

Winston E. Scott- Dean, College of Aeronautics, Florida Institute of Technology, Melbourne, Florida since August 2008. He previously served as Vice President and Deputy General Manager, Engineering and Science Contract Group at Jacobs Engineering, Houston, Texas, from 2006 to 2008 and Executive Director of the Florida Space Authority, Cape Canaveral, Florida, from 2003 to 2006. Mr. Scott’s experience also included serving as a pilot in the U.S. Navy and an astronaut with the National Aeronautic and Space Administration.

EXECUTIVE OFFICERS

P. Bernard Jacob- Vice President of Customer Operations since 2007. He previously served as Vice President of External Affairs and Corporate Services from 2003 to 2007.

Philip C. Raymond- Vice President and Chief Financial Officer since April 2008. He previously served as Vice President and Comptroller of Alabama Power from January 2005 to April 2008 and Eastern Region Internal Auditing Director of SCS from September 2003 through January 2005.

Theodore J. McCullough- Vice President and Senior Production Officer since 2007. He previously served as the Manager of Georgia Power’s Plant Branch from December 2003 to August 2007.

Bentina C. Terry- Vice President of External Affairs and Corporate Services since 2007. She previously served as General Counsel and Vice President of External Affairs for Southern Nuclear from January 2005 to March 2007 and Area Distribution Manager of Georgia Power from February 2004 through January 2005.

Involvement in certain legal proceedings.None.

Promoters and Certain Control Persons.None.

Section 16(a) Beneficial Ownership Reporting Compliance.None.

Code of Ethics

The registrants collectively have adopted a code of business conduct and ethics that applies to each director, officer, and employee of the registrants and their subsidiaries. The code of business conduct and ethics can be found on Southern Company’s website located at www.southerncompany.com. The code of business conduct and ethics is also available free of charge in print to any shareholder by requesting a copy from Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. 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

Southern Company has adopted corporate governance guidelines and committee charters. The corporate governance guidelines and the charters of Southern Company’s Audit Committee, Compensation and Management Succession Committee, Finance Committee, Governance Committee, and Nuclear/Operations Committee can be found on Southern Company’s website located at www.southerncompany.com. The corporate governance guidelines and charters are also available free of charge in print to any shareholder by requesting a copy from Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

In this Compensation Discussion and Analysis (CD&A) and this Form 10-K, references to the “Compensation Committee” are to the Compensation and Management Succession Committee of the Board of Directors of Southern Company.

GUIDING PRINCIPLES AND POLICIES

Southern Company, through a single executive compensation program for all officers of its subsidiaries, drives and rewards both Southern Company financial performance and individual business unit performance.

This executive compensation program is based on a philosophy that total executive compensation must be competitive with the companies in our industry, must be tied to and motivate our executives to meet our short- and long-term performance goals, must foster and encourage alignment of executive interests with the interests of our stockholders and our customers, and must not encourage excessive risk-taking. The program generally is designed to motivate all employees, including executives, to achieve operational excellence and financial goals while maintaining a safe work environment.

The executive compensation program places significant focus on rewarding performance. The program is performance-based in several respects:

• Southern Company’s actual earnings per share (EPS) and Gulf Power’s business unit performance, which includes return on equity (ROE), compared to target performance levels established early in the year, determine actual payouts under the short-term (annual) performance-based compensation program (Performance Pay Program).

• Southern Company common stock (Common Stock) price changes result in higher or lower ultimate values of stock options.

• Southern Company’s dividend payout and total shareholder return compared to those of its industry peers lead to higher or lower payouts under the Performance Dividend Program (performance dividends).

In support of the performance-based pay philosophy, we have no general employment contracts with our named executive officers or guaranteed severance, except upon a change in control, and no pay is conditioned solely upon continued employment of any of the named executive officers, other than base salary.

The pay-for-performance principles apply not only to the named executive officers, but to hundreds of Gulf Power employees. The Performance Pay Program covers almost all of the approximately 1,300 Gulf Power employees. Stock options and performance dividends cover approximately 250 Gulf Power employees. These programs engage our people in our business, which ultimately is good not only for them, but for Gulf Power’s customers and Southern Company’s stockholders.

OVERVIEW OF EXECUTIVE COMPENSATION COMPONENTS

The executive compensation program is composed of several components, each of which plays a different role. The chart below discusses the intended role of each material pay component, what it rewards, and why we use it. Following the chart is additional information that describes how we made 2009 pay decisions.

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	Intended Role and What the Element
Pay Element	Rewards	Why We Use the Element
Base Salary	Base salary is pay for competence in the executive role, with a focus on scope of responsibilities.	Market practice. Provides a threshold level of cash compensation for job performance.
Annual Performance-Based Compensation: Performance Pay Program	The Performance Pay Program rewards achievement of operational, EPS, and business unit financial goals.	Market practice. Focuses attention on achievement of short-term goals that ultimately work to fulfill our mission to customers and lead to increased stockholder value in the long term.
Long-Term Performance-Based Compensation: Stock Options	Stock options reward price increases in Common Stock over the market price on the date of grant, over a 10-year term.	Market practice. Performance-based compensation. Aligns executives’ interests with those of Southern Company’s stockholders.
Long-Term Performance-Based Compensation: Performance Dividends	Performance dividends provide cash compensation dependent on the number of stock options held at year end, Southern Company’s dividends on the Common Stock paid during the year, and Southern Company’s four-year total shareholder return versus industry peers.	Market practice. Performance-based compensation. Enhances the value of stock options and focuses executives on maintaining a significant dividend yield for Southern Company’s stockholders. Aligns executives’ interests with Southern Company’s stockholders’ interests since payouts are dependent on the returns realized by Southern Company’s stockholders versus those of our industry peers.
Retirement Benefits	The Southern Company Deferred Compensation Plan provides the opportunity to defer to future years all or part of base salary and performance-based compensation, except stock options, in either a prime interest rate or Common Stock account. Executives participate in employee benefit plans available to all employees of Gulf Power, including a 401(k) savings plan and the funded Southern Company Pension Plan (Pension Plan).	Market practice. Permitting compensation deferral is a cost-effective method of providing additional cash flow to Gulf Power while enhancing the retirement savings of executives. The purpose of these supplemental plans is to eliminate the effect of tax limitations on the payment of retirement benefits.

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	Intended Role and What the Element
Pay Element	Rewards	Why We Use the Element
	The Supplemental Benefit Plan counts pay, including deferred salary, ineligible to be counted under the Pension Plan and the 401(k) plan due to Internal Revenue Service rules. The Supplemental Executive Retirement Plan counts annual performance-based pay above 15% of base salary for pension purposes.	Represents an important component of competitive market-based compensation in Southern Company’s peer group and generally.
Perquisites and Other Personal Benefits	Personal financial planning maximizes the perceived value of our executive compensation program to executives and allows them to focus on Gulf Power’s operations. Home security systems lower the risk of harm to executives. Club memberships are provided primarily for business use. Relocation benefits cover the costs associated with geographic relocations at the request of the employer. Limited personal use of corporate-owned aircraft associated with business travel.	Perquisites benefit both Gulf Power and executives, at low cost to Gulf Power.
Post-Termination Pay	Change-in-control plans provide severance pay, accelerated vesting, and payment of short- and long-term performance-based compensation upon a change in control of Gulf Power or Southern Company coupled with involuntary termination not for “Cause” or a voluntary termination for “Good Reason.”	Market practice. Providing protections to senior executives upon a change in control minimizes disruption during a pending or anticipated change in control. Payment and vesting occur only upon the occurrence of both an actual change in control and loss of the executive’s position.

MARKET DATA

For the named executive officers, the Compensation Committee reviews compensation data from large, publicly-owned electric and gas utilities. The data was developed and analyzed by Towers Perrin, the compensation consultant retained by the Compensation Committee. The companies included each year in the primary peer group are those whose data is available through the consultant’s database. Those companies are drawn from this list of primarily regulated utilities of $2 billion in revenues and up.

III-6

AGL Resources Inc.	El Paso Corporation	PG&E Corporation
Allegheny Energy, Inc.	Entergy Corporation	Pinnacle West Capital Corporation
Alliant Energy Corporation	EPCO	PPL Corporation
Ameren Corporation	Exelon Corporation	Progress Energy, Inc.
American Electric Power Company, Inc.	FirstEnergy Corp.	Public Service Enterprise Group Inc.
Atmos Energy Corporation	FPL Group, Inc.	Puget Energy, Inc.
Calpine Corporation	Integrys Energy Company, Inc.	Reliant Energy, Inc.
CenterPoint Energy, Inc	MDU Resources, Inc.	Salt River Project
CMS Energy Corporation	Mirant Corporation	SCANA Corporation
Consolidated Edison, Inc.	New York Power Authority	Sempra Energy
Constellation Energy Group, Inc.	Nicor, Inc.	Southern Union Company
CPS Energy	Northeast Utilities	Spectra Energy
DCP Midstream	NRG Energy, Inc.	TECO Energy
Dominion Resources Inc.	NSTAR	Tennessee Valley Authority
Duke Energy Corporation	NV Energy, Inc.	The Williams Companies, Inc.
Dynegy Inc.	OGE Energy Corp.	Wisconsin Energy Corporation
Edison International	Pepco Holdings, Inc.	Xcel Energy Inc.

Southern Company is one of the largest U.S. utility companies based on revenues and market capitalization, and its largest business units are some of the largest in the industry as well. For that reason, the consultant size-adjusts the survey market data in order to fit it to the scope of our business.

In using this market data, market is defined as the size-adjusted 50th percentile of the data, with a focus on pay opportunities at target performance (rather than actual plan payouts). Market data for chief executive officer positions and other positions in terms of scope of responsibilities that most closely resemble the positions held by the named executive officers are reviewed. Based on that data, a total target compensation opportunity is established for each named executive officer. Total target compensation opportunity is the sum of base salary, annual performance-based compensation at the target performance level, and stock option awards with associated performance dividends at a target value. Actual compensation paid may be more or less than the total target compensation opportunity based on actual performance above or below target performance levels. As a result, the compensation program is designed to result in payouts that are market-appropriate given Gulf Power’s and Southern Company’s performance for the year or period.

We did not target a specified weight for base salary or annual or long-term performance-based compensation as a percentage of total target compensation opportunities, nor did amounts realized or realizable from prior compensation serve to increase or decrease 2009 compensation amounts. Total target compensation opportunities for senior management as a group are managed to be at the median of the market for companies of our size and in our industry. The total target compensation opportunity established in 2009 for each named executive officer is shown below.

			Annual		Long-Term		Total Target
			Performance-Based		Performance-Based		Compensation
Name	Salary		Compensation		Compensation		Opportunity
S. N. Story	$	396,084	$	237,650	$	495,105	$	1,128,839
P. C. Raymond	$	228,433	$	102,795	$	137,055	$	468,283
P. B. Jacob	$	230,346	$	103,656	$	138,206	$	472,208
T. J. McCullough	$	182,973	$	73,189	$	73,186	$	329,348
B. C. Terry	$	228,433	$	102,795	$	137,055	$	468,283

For purposes of comparing the value of our compensation program to the market data, stock options are valued at 5.7%, and performance dividend target at 10%, of the average daily Common Stock price for the year preceding the

III-7

grant, both of which represent risk-adjusted present values on the date of grant and are consistent with the methodologies used to develop the market data. For the 2009 grant of stock options and the performance dividend target established for the 2009-2012 performance-measurement period, this value was $4.94 per stock option granted. In the long-term column, 36% of the value shown is attributable to stock options and 64% is attributable to performance dividends. The value of stock options, with the associated performance dividends, declined from 2008. In 2008 and 2009, the value of the dividend equivalents was 10% of the Common Stock price on the stock option grant date, but the value of the stock option declined from 12% to 5.7%. In 2008, the performance dividends represented 45% of the long-term target value and stock options represented 55% of that value. More information on how stock options are valued is reported in the Grants of Plan-Based Award table and the information accompanying it.

As discussed above, the Compensation Committee targets total target compensation opportunities for senior executives as a group at market. Therefore, some executives may be paid somewhat above and others somewhat below market. This practice allows for minor differentiation based on time in the position, scope of responsibilities, and individual performance. The differences in the total pay opportunities for each named executive officer are based almost exclusively on the differences indicated by the market data for persons holding similar positions. The average total target compensation opportunities for the named executive officers for 2009 were at the median of the market data described above. Because of the use of market data from a large number of peer companies for positions that are not identical in terms of scope of responsibility from company to company, we do not consider slight differences material and continue to believe that our compensation program is market-appropriate. Generally, we consider compensation to be within an appropriate range if it is not more or less than 10% of the applicable market data.

In 2008, the Compensation Committee received a detailed comparison of our executive benefits program to the benefits of a group of other large utilities and general industry companies. The results indicated that our overall executive benefits program was at market. Because this data does not change significantly year over year, this study is only updated every few years.

DESCRIPTION OF KEY COMPENSATION COMPONENTS

2009 Base Salary

The named executive officers are each within a position level with a base salary range that is established under the direction of the Compensation Committee using the market data described above. Consistent with the broad-based compensation program for 2009, there were no base salary adjustments for the named executive officers.

2009 Performance-Based Compensation

This section describes our performance-based compensation program in 2009. The Compensation Committee approved changes to that program in 2009, to be effective in 2010. These changes are described in the last section of this CD&A entitled 2010 Executive Compensation Program Changes.

Achieving Operational and Financial Goals — Our Guiding Principle for Performance-Based Compensation

Our number one priority is to provide our customers outstanding reliability and superior service at low prices while achieving a level of financial performance that benefits Southern Company’s stockholders in the short and long term.

In 2009, we strove for and rewarded:

• Continued industry-leading reliability and customer satisfaction, while maintaining our low retail prices relative to the national average; and

• Meeting energy demand with the best economic and environmental choices.

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In 2009, we also focused on and rewarded:

• Southern Company EPS growth;

• Gulf Power ROE in the top quartile of comparable electric utilities;

• Common Stock dividend growth;

• Long-term, risk-adjusted Southern Company total shareholder return; and

• Financial Integrity — an attractive risk-adjusted return, sound financial policy, and a stable “A” credit rating.

The performance-based compensation program is designed to encourage Gulf Power to achieve these goals.

The Southern Company Chief Executive Officer, with the assistance of Southern Company’s Human Resources staff, recommends to the Compensation Committee program design and award amounts for senior executives, including the named executive officers.

2009 Annual Performance Pay Program

Program Design

The Performance Pay Program is Southern Company’s annual performance-based compensation program. Almost all employees of Gulf Power are participants, including the named executive officers, for a total of over 1,300 Gulf Power participants.

The performance measured by the program uses goals set at the beginning of each year by the Compensation Committee.

An illustration of the annual Performance Pay Program goal structure for 2009 is provided below.

• Operational goals for 2009 were safety, customer satisfaction, plant availability, transmission and distribution system reliability, inclusion, and for Southern Company Generation, operations and maintenance cost performance. Each of these operational goals is explained in more detail under Goal Details below. The result of all operational goals is averaged and multiplied by the bonus impact of the EPS and business unit financial goals. The amount for each goal can range from 0.90 to 1.10 or can be 0.00 if a threshold performance level is not achieved as more fully described below. The level of achievement for each operational goal is determined and the results are averaged.

• Southern Company EPS is weighted at 50% of the financial goals. EPS is defined as earnings from continuing operations divided by average shares outstanding during the year. The EPS performance measure is applicable to all participants in the Performance Pay Program, including the named executive officers.

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• Business unit financial performance is weighted at 50% of the financial goals. Gulf Power’s financial performance goal is ROE, which is defined as Gulf Power’s net income divided by average equity for the year. For Southern Company Generation, it is calculated using a corporate-wide weighted average of all the business unit financial performance goals, including primarily the ROE of Gulf Power and affiliated companies, Alabama Power, Georgia Power, and Mississippi Power. For Mr. McCullough, the business unit financial goal was weighted 30% Gulf Power ROE and 20% Southern Company Generation financial goal.

The Compensation Committee may make adjustments, both positive and negative, to goal achievement for purposes of determining payouts. Such adjustments include the impact of items considered extraordinary or unusual in nature, infrequent in occurrence, outside of normal operations, or not anticipated in the business plan when the earnings goal was established, and of sufficient magnitude to warrant recognition. The Compensation Committee made an adjustment in 2009 to eliminate the effect of a $202 million charge to Southern Company earnings taken in 2009. The charge related to the settlement agreement with MC Asset Recovery, LLC (MCAR) to resolve an action which arose out of the bankruptcy proceeding of Mirant Corporation, a former subsidiary of Southern Company until its spin-off in April 2001. The settlement included an agreement by Southern Company to pay MCAR $202 million, which was paid in mid-2009. This adjustment increased the average payout for 2009 performance by approximately 30%.

Under the terms of the program, no payout can be made if Southern Company’s current earnings are not sufficient to fund its Common Stock dividend at the same level or higher than the prior year.

Goal Details

Operational Goals:

Customer Satisfaction — Gulf Power uses customer satisfaction surveys to evaluate its performance. The survey results provide an overall ranking for Gulf Power, as well as a ranking for each customer segment: residential, commercial, and industrial.

Reliability — 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.

Availability — Peak season equivalent forced outage rate is an indicator of 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.

Safety — Southern Company’s Target Zero program is focused on continuous improvement in having a safe work environment. The performance is measured by the Occupational Safety and Health Administration recordable incident rate.

Inclusion/Diversity — The inclusion program seeks to improve our inclusive workplace. This goal includes measures for work environment (employee satisfaction survey), representation of minorities and females in leadership roles, and supplier diversity.

Southern Company capital expenditures “gate” or threshold goal — For 2009, Southern Company strived to manage total capital expenditures, excluding nuclear fuel, for the participating business units at or below $4.5 billion and Gulf Power strived to manage such expenditures at or below $478 million. If the Southern Company or Gulf Power capital expenditure target is exceeded, total operational goal performance is capped at 0.90 regardless of the actual operational goal results. Adjustments to the goal may occur due to significant events not anticipated in Southern Company’s and Gulf Power’s business plans established early in 2009, such as acquisitions or disposition of assets, new capital projects, and other events.

For Mr. McCullough, the operational goals were weighted 60% based on Gulf Power’s operational goals and 40% based on Southern Company Generation’s operational goals.

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The range of performance levels established for each operational goal is detailed below.

			Availability
			Gulf Power/
			Southern
Level of	Customer		Company
Performance	Satisfaction	Reliability	Generation (%)	Safety	Inclusion
Maximum (1.10)	Top quartile for each customer segment	Improve historical performance	2.25/2.00	0.62 or top quartile	Significant improvement
Target (1.00)	Top quartile overall	Maintain historical performance	3.00/2.75	0.988	Improve
Threshold (0.90)	2nd quartile	Below historical performance	4.00/3.75	1.373	Below expectations
0 Trigger	At or below median	Significant issues	9.00/6.00	Each quarter at threshold or below	Significant issues

EPS and Business Unit Financial Performance:

The range of EPS and business unit financial goals for 2009 is shown below. The ROE goal varies from the allowed retail ROE range due to state regulatory accounting requirements, wholesale activities, other non-jurisdictional revenues and expenses, and other activities not subject to state regulation.

								Payout Factor
								at Associated		Payout Below
	EPS, excluding		Business Unit					Level of		Threshold for
	MCAR		Financial					Operational		Operational
Level of	Settlement		Performance			Payout		Goal		Goal
Performance	Impact		ROE			Factor		Achievement		Achievement
Maximum	$	2.50		13.7	%		2.00		2.20		0.00
Target	$	2.375		12.7	%		1.00		1.00		0.00
Threshold	$	2.25		11.00	%		0.01		0.01		0.00
Below threshold	<$	2.25		<11.00	%		0.00		0.00		0.00

2009 Achievement

Each named executive officer had a target Performance Pay Program opportunity, based on his or her position, set by the Compensation Committee at the beginning of 2009. Targets are set as a percentage of base salary. Ms. Story’s target was set at 60%. For Ms. Terry and Messrs. Jacob and Raymond, it was set at 45% and for Mr. McCullough, it was set at 40%. Actual payouts were determined by adding the payouts derived from EPS and business unit financial performance goal achievement for 2009 and multiplying that sum by the result of the operational goal achievement. The gate goal target was not exceeded and therefore did not affect payouts. Actual 2009 goal achievement is shown in the following table. The EPS result shown in the table is adjusted for the MCAR settlement charge taken in 2009 as described above. Therefore, payouts were determined using EPS performance results that differed from the results reported in the financial statements of Southern Company in Item 8 herein. EPS, as determined in accordance with accounting principles generally accepted in the United States and as reported by Southern Company, was $2.07 per share.

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Business

Unit

Total

EPS

Financial

Weighted

Operational

Excluding

EPS Goal

Business

Performance

Financial

Total

Goal

MCAR

Performance

Unit

Factor

Performance

Payout

Business

Multiplier

Settlement

Factor (50%

Financial

(50%

Factor

Factor

Unit

(A)

Impact

Weight)

Performance

Weight)

(B)

(AxB)

Gulf Power

1.08

$

2.32

0.57

12.18

%

0.69

0.63

0.68

Southern Company Generation

1.08

$

2.32

0.57

Corporate Average

0.90

0.73

0.79

Note that the Total Payout Factor may vary from the Total Weighted Financial Performance Factor multiplied by the Operational Goal Multiplier due to rounding. To calculate the Performance Pay Program amount, the target opportunity is multiplied by the Total Payout Factor.

Actual performance, as adjusted, was below the target performance levels established by the Compensation Committee in early 2009; therefore, the payout levels were below the target pay opportunities that were established. More information on how target pay opportunities are established is provided under the Market Data section in this CD&A.

The table below shows the pay opportunity set in early 2009 for the annual Performance Pay Program payout at target-level performance and the actual payout based on the actual performance, as adjusted, shown above.

	Target Annual Performance		Actual Annual Performance
Name	Pay Program Opportunity ($)		Pay Program Payout ($)
S. N. Story		237,650		161,602
P. C. Raymond		102,795		69,901
P. B. Jacob		103,656		70,486
T. J. McCullough		73,189		53,428
B. C. Terry		102,795		69,901

Stock Options

Options to purchase Common Stock are granted annually and were granted in 2009 to the named executive officers and about 250 other employees of Gulf Power. Options have a 10-year term, vest over a three-year period, fully vest upon retirement or termination of employment following a change in control, and expire at the earlier of five years from the date of retirement or the end of the 10-year term. The Compensation Committee changed the stock option vesting provisions associated with retirement for stock options granted in 2009 to the executive officers of Southern Company, including Ms. Story. For these grants made in 2009, unvested options are forfeited if she retires and accepts a position with a peer company within two years of retirement. The Compensation Committee made this change to provide more retention value to the stock option awards, to provide an inducement to not seek a position with a peer company, and to limit the post-termination compensation of executive officers of Southern Company who do accept positions with a peer company. Ms. Story became retirement-eligible in early 2010.

As described in the Market Data section above, the Compensation Committee established a target long-term performance-based compensation value for each named executive officer. The number of stock options granted, with associated performance dividends, was determined by dividing that long-term value by the value of a stock option with associated performance dividends. The value of each stock option was derived using the Black-Scholes stock option pricing model. The assumptions used in calculating that amount are discussed in Note 8 to the financial statements of Gulf Power in Item 8 herein. For 2009, the Black-Scholes value on the grant date was $1.80 per stock option. As described in the Market Data section above, the value of the associated performance dividends was $3.14 per stock option which was 10% of the Common Stock price on the grant date. Therefore, the target value of each stock option, with associated performance dividends, was $4.94 per stock option. The calculation of the 2009 stock option grants for the named executive officers is shown below.

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The calculation of the 2009 stock option grants for the named executive officers is shown below.

	Long-Term		Value Per		Number of Stock
Name	Value		Stock Option		Options Granted
S. N. Story		495,105	$	4.94		100,223
P. C. Raymond		137,055	$	4.94		27,744
P. B. Jacob		138,206	$	4.94		27,977
T. J. McCullough		73,186	$	4.94		14,815
B. C. Terry		137,055	$	4.94		27,744

More information about the stock option program is contained in the Grant of Plan Based Awards table and the information accompanying it.

Performance Dividends

All option holders, including the named executive officers, can receive performance-based dividend equivalents on stock options held at the end of the year. Performance dividends can range from 0% to 100% of the Common Stock dividend paid during the year per option held at the end of the year. Actual payout will depend on Southern Company’s total shareholder return over a four-year performance measurement period compared to a group of other electric and gas utility companies. The peer group is determined at the beginning of each four-year performance-measurement period. The peer group varies from the Market Data peer group due to the timing and criteria of the peer selection process. The peer group for performance dividends is set by the Compensation Committee at the beginning of the four-year performance-measurement period. However, despite these timing differences, there is substantial overlap in the companies included.

Total shareholder return is calculated by measuring the ending value of a hypothetical $100 invested in each company’s common stock at the beginning of each of 16 quarters. In the final year of the performance-measurement period, Southern Company’s ranking in the peer group is determined at the end of each quarter and the percentile ranking is multiplied by the actual Common Stock dividend paid in that quarter. To determine the total payout per stock option held at the end of the performance-measurement period, the four quarterly amounts earned are added together.

No performance dividends are paid if Southern Company’s earnings are not sufficient to fund a Common Stock dividend at least equal to that paid in the prior year.

2009 Payout

The peer group used to determine the 2009 payout for the 2006-2009 performance-measurement period consisted of utilities with revenues of $1.2 billion or more with regulated revenues of 60% or more. Those companies are listed below.

Allegheny Energy, Inc.	Entergy Corporation	Pinnacle West Capital Corp.
Alliant Energy Corporation	Exelon Corporation	Progress Energy, Inc.
Ameren Corporation	FPL Group, Inc.	SCANA Corporation
American Electric Power Company, Inc.	NiSource Inc.	Sempra Energy
CenterPoint Energy, Inc.	Northeast Utilities	Westar Energy Corporation
CMS Energy Corporation	NSTAR	Wisconsin Energy Corporation
Consolidated Edison, Inc.	NV Energy, Inc.	Xcel Energy Inc.
DPL, Inc.	Pepco Holdings, Inc.
Edison International	PG&E Corporation

The scale below determined the percentage of each quarter’s dividend paid in the last year of the performance-measurement period to be paid on each stock option held at December 31, 2009 based on the 2006-2009 performance-measurement period. Payout for performance between points was interpolated on a straight-line basis.

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Performance vs. Peer Group	Payout (% of Each Quarterly Dividend Paid)
90th percentile or higher		100
50th percentile (target)		50
10th percentile or lower		0

Southern Company’s total shareholder return performance as measured at the end of each quarter of the final year of the four-year performance-measurement period ending with 2009 was the 83^rd, 83^rd, 53^rd, and 38^th percentile, respectively, resulting in a total payout of 64% of the full year’s Common Stock dividend, or $1.10. This amount was multiplied by each named executive officer’s outstanding stock options at December 31, 2009 to calculate the payout under the program. The amount paid is included in the Non-Equity Incentive Plan Compensation column in the Summary Compensation Table.

2012 Opportunity

The Compensation Committee selected two peer groups for the 2009-2012 performance-measurement period (which will be used to determine the 2012 payout amount). The results of the two peer groups will be averaged to determine the payment level. One peer group selected is a published index, the Philadelphia Utility Index. The other peer group (custom peer group) is a group of companies that the Company believes are similar to the Company in terms of business models, including a mix of regulated and non-regulated revenues.

The companies in the Philadelphia Utility Index are listed below.

Ameren Corporation	Exelon Corporation
American Electric Power Company, Inc.	FirstEnergy Corp.
CenterPoint Energy, Inc.	FPL Group, Inc.
Consolidated Edison, Inc.	Northeast Utilities
Constellation Energy Group, Inc.	PG&E Corporation
Dominion Resources Inc.	Progress Energy, Inc.
DTE Energy Company	Public Service Enterprise Group Inc.
Duke Energy Corporation	The AES Corporation
Edison International	Xcel Energy Inc.
Entergy Corporation

The companies in the custom peer group are listed below.

American Electric Power Company, Inc.	PG&E Corporation
Consolidated Edison, Inc.	Progress Energy, Inc.
Duke Energy Corporation	Wisconsin Energy Corporation
Northeast Utilities	Xcel Energy Inc.
NSTAR

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The scale below will determine the percentage of each quarter’s dividend paid in the last year of the performance-measurement period to be paid on each option held at December 31, 2012, based on the 2009-2012 performance-measurement period. Payout for performance between points will be interpolated on a straight-line basis.

Performance vs. Peer Groups	Payout (% of Each Quarterly Dividend Paid)
90th percentile or higher		100
50th percentile (target)		50
10th percentile or lower		0

See the Grants of Plan-Based Awards table and the accompanying information for more information about threshold, target, and maximum payout opportunities for the 2009-2012 Performance Dividend Program.

Timing of Performance-Based Compensation

As discussed above, Southern Company EPS and Gulf Power’s financial performance goal for the 2009 Performance Pay Program were established at the February 2009 Compensation Committee meeting. Annual stock option grants also were made at that meeting. The establishment of performance-based compensation goals and the granting of stock options were not timed with the release of material, non-public information. This procedure was consistent with prior practices. Stock option grants are made to new hires or newly-eligible participants on preset, regular quarterly dates that were approved by the Compensation Committee. The exercise price of options granted to employees in 2009 was the closing price of the Common Stock on the grant date or the last trading day before the grant date if the grant date was not a trading day.

Post-Employment Compensation

As mentioned above, we provide certain post-employment compensation to employees, including the named executive officers:

Retirement Benefits

Generally, all full-time employees of Gulf Power, including the named executive officers, participate in our funded Pension Plan after completing one year of service. Normal retirement benefits become payable when participants both attain age 65 and complete five years of participation. We also provide unfunded benefits that count salary and annual Performance Pay Program payouts that are ineligible to be counted under the Pension Plan. (These plans are the Supplemental Benefit Plan and the Supplemental Executive Retirement Plan that are described in the chart on pages III-5 and III-6 of this CD&A.) See the Pension Benefits table and the information accompanying it for more information about pension-related benefits.

Gulf Power also provides the Deferred Compensation Plan which is an unfunded plan that permits participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement, disability, death, or other separation from service. Up to 50% of base salary and up to 100% of performance-based compensation, except stock options, may be deferred at the election of eligible employees. All of the named executive officers are eligible to participate in the Deferred Compensation Plan. See the Nonqualified Deferred Compensation table and the information accompanying it for more information about the Deferred Compensation Plan.

Change-in-Control Protections

The Compensation Committee initially approved the change-in-control protection program in 1998. The program provided some level of severance benefits to all employees not part of a collective bargaining unit, if the conditions of the program were met, as described below. The Compensation Committee established this program and the levels of severance amount in order to provide certain compensatory protections to executives upon a change in control and thereby allow them to negotiate aggressively with a prospective purchaser. Providing such protections to our employees in general would minimize disruption during a pending or anticipated change in control. For all

III-15

participants, payment and vesting would occur only upon the occurrence of both an actual change in control and loss of the individual’s position. In 2009, the Compensation Committee directed Towers Perrin to review best practices for change-in-control programs and directed management to recommend any necessary changes to the program to meet those best practices. The review of the program was completed in 2009 and changes were made effective in late 2009.

Change-in-control protections, including severance pay and, in some situations, vesting or payment of long-term performance-based awards, are provided upon a change in control of Southern Company or Gulf Power coupled with an involuntary termination not for “Cause” or a voluntary termination for “Good Reason.” This means there is a “double trigger” before severance benefits are paid;i.e., there must be both a change in control and a termination of employment.

If the conditions described above are met, the named executive officers are entitled to severance payments equal to one or three times their base salary plus the annual performance-based compensation amount assuming target-level performance. Most officers, including Gulf Power’s named executive officers, are entitled to severance payments equal to one timestheir base salary plus the annual Performance Pay Program amount assuming target-level performance. Ms. Story is entitled to the larger amount.

Prior to the changes made in 2009, the named executive officers, other than Ms. Story, were entitled to severance payments of two times their base salary plus the target-level annual Performance Pay Program amount. The changes made in 2009 also eliminated the broad-based change-in-control severance program.

More information about post-employment compensation, including severance arrangements under our change-in-control program, is included in the section entitled Potential Payments upon Termination or Change in Control.

Executive Stock Ownership Requirements

Effective January 1, 2006, the Compensation Committee adopted Common Stock ownership requirements for officers of Southern Company and its subsidiaries that are in a position of vice president or above. All of the named executive officers are covered by the requirements. The guidelines were implemented to further align the interest of officers and Southern Company’s stockholders by promoting a long-term focus and long-term share ownership.

The types of ownership arrangements counted toward the requirements are shares owned outright, those held in Southern Company-sponsored plans, and Common Stock accounts in the Deferred Compensation Plan and the Supplemental Benefit Plan. One-third of vested Southern Company stock options may be counted, but if so, the ownership requirement is doubled.

The requirements are expressed as a multiple of base salary as per the table below.

	Multiple of Salary Without	Multiple of Salary Counting
Name	Counting Stock Options	1/3 of Vested Options
S. N. Story	3 Times	6 Times
P. C. Raymond	2 Times	4 Times
P. B. Jacob	2 Times	4 Times
T. J. McCullough	1 Times	2 Times
B. C. Terry	2 Times	4 Times

Current officers have until September 30, 2011 to meet the applicable ownership requirement. Newly-elected officers have five years from the date of their election to meet the applicable ownership requirement.

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Impact of Accounting and Tax Treatments on Compensation

None of the compensation paid to Gulf Power’s employees, including the named executive officers, is subject to the restrictions under Section 162(m) of the Internal Revenue Code of 1986, as amended (Code).

Policy on Recovery of Awards

Southern Company’s 2006 Omnibus Incentive Compensation Plan provides that if Southern Company or Gulf Power is required to prepare an accounting restatement due to material noncompliance as a result of misconduct, and if an executive officer knowingly or grossly negligently engaged in or failed to prevent the misconduct or is subject to automatic forfeiture under the Sarbanes-Oxley Act of 2002, the executive officer will reimburse Gulf Power the amount of any payment in settlement of awards earned or accrued during the 12-month period following the first public issuance or filing that was restated.

Southern Company Policy Regarding Hedging the Economic Risk of Stock Ownership

Southern Company’s policy is that insiders, including outside directors, will not trade in Southern Company options on the options market and will not engage in short sales.

2010 Executive Compensation Program Changes

In 2009, the Compensation Committee made certain key changes to the performance-based compensation program that affect all employees of Gulf Power, including the named executive officers. Changes were made to both the annual and long-term performance-based compensation programs.

Annual Performance Pay Program

For annual performance-based compensation to be earned in 2010, the Compensation Committee changed the goal weights and lowered the maximum payout opportunity. Under the program in effect since 2000, the 2009 goals were weighted 50% EPS and 50% ROE with an adjustment of plus or minus 10% based on operational goal performance. The maximum payout opportunity was 220% of the target opportunity. (For more information, see the description of the Performance Pay Program in the 2009 Performance Based Compensation section in this CD&A.) Under the program effective in 2010, the goals are weighted one-third EPS, one-third ROE, and one-third operational goals. The maximum payout opportunity is reduced to 200% of target.

Long-Term Performance-Based Compensation Program

The long-term performance-based compensation program that has been in effect for many years has consisted of stock options with associated performance dividends. Effective in 2010, stock options were granted without associated performance dividends. Performance dividends accounted for approximately 64% of the total long-term performance-based compensation target value for 2009. In 2010, stock options represent 40% of the total value and a new long-term performance-based compensation component was granted: performance share units. Performance share units represent 60% of the total long-term performance-based compensation target value. A grant date fair value per unit is determined. For the grant made in 2010, the value per unit was $30.13. The total target value for performance share units is divided by the value per unit to determine the number of performance share units granted to each participant, including the named executive officers. Each performance share unit represents one share of Common Stock. At the end of a three-year performance-measurement period, the number of units will be adjusted up or down (zero to 200%) based on Southern Company’s total shareholder return relative to that of its peers in the Philadelphia Utility Index and the custom peer group. (The performance metric, performance scale, and the peer groups used for the performance share units are the same as that currently used for the Performance Dividend Program.) The number of performance share units earned will be paid in Common Stock. No dividends or dividend equivalents will be paid or earned on the performance share units.

The Compensation Committee also approved a transition period for the Performance Dividend Program. There are three performance-measurement periods that are still open: 2007-2010, 2008-2011, and 2009-2012. For these open

III-17

periods, the performance at the end of each period will be determined as described above in this CD&A, and the amount earned will be paid on the number of stock options granted prior to 2010 that a participant holds at the end of each period. Therefore, there will be three additional payouts under the Performance Dividend Program, but the number of stock options upon which payment will be based will be limited to those granted prior to 2010.

COMPENSATION COMMITTEE REPORT

The Compensation Committee met with management to review and discuss the CD&A. Based on such review and discussion, the Compensation Committee recommended to the Southern Company Board of Directors that the CD&A be included in Gulf Power’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009. The Southern Company Board of Directors approved that recommendation.

Members of the Compensation Committee:

J. Neal Purcell, Chair
Henry A. Clark, III
H. William Habermeyer, Jr.
Donald M. James

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SUMMARY COMPENSATION TABLE

The Summary Compensation Table shows the amount and type of compensation received by the Chief Executive Officer, any Chief Financial Officer, and the next three most highly-paid executive officers who served in 2009. Collectively, these officers are referred to as the “named executive officers.”

													Change in
													Pension
													Value and
													Nonquali-
											Non-		fied
											Equity		Deferred		All
											Incentive		Compensa-		Other
							Stock		Option		Plan		tion		Compensa-
Name and			Salary		Bonus		Awards		Awards		Compensation		Earnings		tion		Total
Principal Position	Year		($)		($)		($)		($)		($)		($)		($)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Susan N. Story		2009		411,318		0		0		180,401		455,257		403,615		41,374		1,491,965
President, Chief		2008		390,602		0		0		102,872		509,067		128,423		39,109		1,170,073
Executive Officer,		2007		366,578		0		0		179,105		404,421		231,120		37,196		1,218,420
and Director
Philip C. Raymond*		2009		237,219		0		0		49,939		146,636		147,437		180,666		761,897
Vice President and		2008		215,880		23,731		0		21,283		181,206		48,120		44,446		534,666
Chief Financial Officer
P. Bernard Jacob		2009		239,205		0		0		50,359		146,661		199,239		23,487		658,951
Vice President		2008		227,419		0		0		32,670		181,151		103,293		22,219		566,752
		2007		213,374		0		0		57,371		152,730		125,674		22,726		571,875
Theodore J. McCullough		2009		190,010		0		0		26,667		105,148		111,520		17,805		451,150
Vice President		2008		180,717		0		0		20,790		139,937		30,798		78,720		450,962
		2007		154,087		17,000		0		22,450		107,045		30,674		29,962		361,218
Bentina C.Terry		2009		237,219		0		0		49,939		134,728		48,437		25,427		495,750
Vice President		2008		222,172		5,150		0	��	30,616		166,985		13,845		26,250		465,018
		2007		193,869		18,232		0		38,592		140,268		13,802		64,210		468,973

* Mr. Raymond became an executive officer of Gulf Power in 2008.

Column (e)

No equity-based compensation has been awarded to the named executive officers, or any other employees of Gulf Power, other than Stock Option Awards which are reported in column (f).

Column (f)

This column reports the aggregate grant date fair value. See Note 8 to the financial statements of Gulf Power in Item 8 herein for a discussion of the assumptions used in calculating these amounts.

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Column (g)

The amounts in this column are the aggregate of the payouts under the annual Performance Pay Program and the Performance Dividend Program attributable to performance periods ended December 31, 2009 that are discussed in detail in the CD&A. The amounts paid under each program to the named executive officers are shown below.

	Annual Performance-
Name	Based Compensation ($)		Performance Dividends ($)		Total ($)
S. N. Story		161,602		293,655		455,257
P. C. Raymond		69,901		76,735		146,636
P. B. Jacob		70,486		76,175		146,661
T. J. McCullough		53,428		51,720		105,148
B. C. Terry		69,901		64,827		134,728

Column (h)

This column reports the aggregate change in the actuarial present value of each named executive officer’s accumulated benefit under the Pension Plan and the supplemental pension plans (collectively, Pension Benefits) during 2007, 2008, and 2009. The amount included for 2007 is the difference between the actuarial present values of the Pension Benefits measured as of September 30, 2006 and September 30, 2007. However, the amount for 2008 is the difference between the actuarial values of the Pension Benefits measured as of September 30, 2007 and December 31, 2008 - 15 months rather than one year. September 30 was used as the measurement date prior to 2008, because it was the date as of which Southern Company measured its retirement benefit obligations for accounting purposes. Starting in 2008, Southern Company changed its measurement date to December 31. The amount for 2009 is the difference between the actuarial values of the Pension Benefits measured as of December 31, 2008 and December 31, 2009. The Pension Benefits as of each measurement date are based on the named executive officer’s age, pay, and service accruals and the plan provisions applicable as of the measurement date. The actuarial present values as of each measurement date reflect the assumptions Gulf Power selected for cost purposes as of that measurement date; however, the named executive officers were assumed to remain employed at Gulf Power or other Southern Company subsidiary until their benefits commence at the pension plans’ stated normal retirement date, generally age 65. As a result, the amounts in column (h) related to Pension Benefits represent the combined impact of several factors: growth in the named executive officer’s Pension Benefits over the measurement year; impact on the total present values of one year shorter discounting period due to the named executive officer being one year closer to normal retirement; impact on the total present values attributable to changes in assumptions from measurement date to measurement date; and impact on the total present values attributable to plan changes between measurement dates.

The present values of accumulated Pension Benefits as of September 30, 2007 reflect new provisions regarding the form and timing of payments from the supplemental pension plans. These changes brought those plans into compliance with Section 409A of the Code. The key change was to the form of payment. Instead of providing monthly payments for the lifetime of each named executive officer and his/her spouse, these plans will pay the single sum value of those benefits for an average lifetime in 10 annual installments. Calculations of the present value of accumulated benefits calculations shown prior to September 30, 2007 reflect supplemental pension benefits being paid monthly for the lifetimes of named executive officers and their spouses. The 2007 change in pension value reported in column (h) for each named executive officer is greater than what it otherwise would have been due to the change in the form of payment.

For more information about the Pension Benefits and the assumptions used to calculate the actuarial present value of accumulated benefits as of December 31, 2009, see the information following the Pension Benefits table. The key differences between assumptions used for the actuarial present values of accumulated benefits calculations as of December 31, 2008 and December 31, 2009 follow:

§	Discount rate for the Pension Plan was decreased to 5.95% as of December 31, 2009 from 6.75% as of December 31, 2008
§	Discount rate for the supplemental pension plans was decreased to 5.60% as of December 31, 2009 from 6.75% as of December 31, 2008

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§ Unpaid annual performance-based compensation was assumed to be 130% of target as of December 31, 2009 and 135% of target was assumed as of December 31, 2008

This column also reports above-market earnings on deferred compensation under the Deferred Compensation Plan (DCP). There were no above-market earnings on deferred compensation in 2009. For more information about the DCP, see the Nonqualified Deferred Compensation table and information accompanying it.

The table below itemizes the amounts reported in this column.

			Change in		Above-Market
			Pension		Earnings on Deferred
			Value		Compensation		Total
Name	Year		($)		($)		($)
S. N. Story		2009		403,615		0		403,615
		2008		128,423		0		128,423
		2007		221,213		9,907		231,120
P. C. Raymond		2009		147,437		0		147,437
		2008		48,120		0		48,120
P. B. Jacob		2009		199,239		0		199,239
		2008		103,293		0		103,293
		2007		125,316		358		125,674
T. J. McCullough		2009		111,520		0		111,520
		2008		30,798		0		30,798
		2007		30,607		67		30,674
B. C. Terry		2009		48,437		0		48,437
		2008		13,845		0		13,845
		2007		13,729		73		13,802

Column (i)

This column reports the following items: perquisites; tax reimbursements by the employing company on certain perquisites; the employing company’s contributions in 2009 to the Southern Company Employee Savings Plan (ESP), which is a tax-qualified defined contribution plan intended to meet requirements of Section 401(k) of the Code; and the employing company’s contributions in 2009 under the Southern Company Supplemental Benefit Plan (Non-Pension Related) (SBP). The SBP is described more fully in the information following the Nonqualified Deferred Compensation table.

The amounts reported are itemized below.

			Tax
	Perquisites		Reimbursements		ESP		SBP		Total
Name	($)		($)		($)		($)		($)
S. N. Story		20,391		6		12,495		8,482		41,374
P. C. Raymond		123,748		44,820		12,098		0		180,666
P. B. Jacob		9,838		3,088		10,561		0		23,487
T. J. McCullough		7,346		1,220		9,239		0		17,805
B. C. Terry		10,358		4,479		10,590		0		25,427

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Description of Perquisites

Personal Financial Planningis provided for most officers of Gulf Power, including all of the named executive officers. Gulf Power pays for the services of the financial planner on behalf of the officers, up to a maximum amount of $8,700 per year, after the initial year that the benefit is provided. In the initial year, the allowed amount is $15,000. The employing company also provides a five-year allowance of $6,000 for estate planning and tax return preparation fees.

Personal Use of Company-Provided Club Memberships.The employing company provides club memberships to certain officers, including all of the named executive officers. The memberships are provided for business use; however, personal use is permitted. The amount included reflects the pro-rata portion of the membership fees paid by the employing company that are attributable to the named executive officers’ personal use. Direct costs associated with any personal use, such as meals, are paid for or reimbursed by the employee and therefore are not included.

Relocation Benefits.These benefits are provided to cover the costs associated with geographic relocation. In 2009, Mr. Raymond received relocation benefits in the amount of $110,596.

Personal Use of Corporate-Owned Aircraft.Southern Company owns aircraft that are used to facilitate business travel. If seating is available, Southern Company permits a spouse or other family member to accompany an employee on a flight. However, because in such cases the aircraft is being used for a business purpose, there is no incremental cost associated with the family travel and no amounts are included for such travel. Any additional expenses incurred that are related to family travel are included. Also, for Ms. Story only, effective in 2009, limited personal use that is associated with business travel is permitted; however, she had no such use in 2009.

Home Security Systems.Gulf Power pays for the services of third-party providers for the installation, maintenance, and monitoring of the named executive officers’ home security systems.

Other Miscellaneous Perquisites.The amount included reflects the full cost to Gulf Power of providing the following items: personal use of company provided tickets for sporting and other entertainment events and gifts distributed to and activities provided to attendees at company-sponsored events.

For Ms. Story, effective in 2009, tax reimbursements are no longer made on perquisites, except on any relocation benefits.

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GRANTS OF PLAN-BASED AWARDS MADE IN 2009

This table provides information on stock option grants made and goals established for future payouts under Gulf Power’s performance-based compensation programs during 2009 by the Compensation Committee. In this table, the annual Performance Pay Program and performance dividend payouts are referred to as PPP and PDP, respectively.

															Grant
															Date
											All Other				Fair
											Option				Value
											Awards:		Exercise		of
											Number of		or Base		Stock
				Estimated Possible Payouts Under Non-Equity							Securities		Price of		and
				Incentive Plan Awards							Underlying		Option		Option
	Grant				Threshold		Target		Maximum		Options		Awards		Awards
Name	Date				($)		($)		($)		(#)		($/Sh)		($)
(a)	(b)				(c)		(d)		(e)		(f)		(g)		(h)
S. N. Story		2/16/2009		PPP		2,139		237,650		522,830
				PDP		11,546		230,920		461,839		100,223		31.39		180,401
P. C. Raymond		2/16/2009		PPP		925		102,795		226,149
				PDP		3,017		60,342		120,683		27,744		31.39		49,939
P. B. Jacob		2/16/2009		PPP		933		103,656		228,043
				PDP		2,995		59,901		119,803		27,977		31.39		50,359
T. J. McCullough		2/16/2009		PPP		659		73,189		161,016
				PDP		2,034		40,671		81,341		14,815		31.39		26,667
B. C. Terry		2/16/2009	��	PPP		925		102,795		226,149
				PDP		2,549		50,978		101,956		27,744		31.39		49,939

Columns (c), (d), and (e)

The amounts reported as PPP reflect the amounts established by the Compensation Committee in early 2009 to be paid for certain levels of performance as of December 31, 2009 under the annual Performance Pay Program. Under that program, the Compensation Committee assigns each named executive officer a target opportunity, expressed as a percentage of base salary, which is paid for target-level performance under the Performance Pay Program. The target opportunities established for the named executive officers for 2009 performance were 60% for Ms. Story, 45% for Ms. Terry and Messrs. Jacob and Raymond, and 40% for Mr. McCullough. The payout for threshold performance was set at a determined amount of less than one percent of the target opportunity and the maximum amount payable was set at 2.20 times the target. The amount paid to each named executive officer under the Performance Pay Program for actual 2009 performance is included in the Non-Equity Incentive Plan Compensation column in the Summary Compensation Table and is itemized in the notes following that table. More information about the annual Performance Pay Program, including the applicable performance criteria established by the Compensation Committee, is provided in the CD&A.

Southern Company also has a long-term performance-based compensation program, the Performance Dividend Program, which has been adopted by Gulf Power and SCS. It pays performance-based dividend equivalents based on Southern Company’s total shareholder return (TSR) compared with the TSR of its peer companies over a four-year performance-measurement period. The Compensation Committee establishes the level of payout for prescribed levels of performance over the performance-measurement period.

In February 2009, the Compensation Committee established the Performance Dividend Program goal for the four-year performance-measurement period beginning on January 1, 2009 and ending on December 31, 2012. The amount earned in 2012 based on the performance for 2009-2012 will be paid following the end of the period. However, no amount is earned and paid unless the Compensation Committee approves the payment at the beginning

III-23

of the final year of the performance-measurement period. Also, nothing is earned unless Southern Company’s earnings are sufficient to fund a Common Stock dividend at least equal to that paid in the prior year.

The Performance Dividend Program pays to all option holders a percentage of the Common Stock dividend paid to Southern Company’s stockholders in the last year of the performance-measurement period. It can range from approximately 2.5% for performance above the 10th percentile compared with the performance of the peer companies to 100% of the dividend if Southern Company’s total shareholder return is at or above the 90th percentile. That amount is then paid per option granted prior to 2010 and held at the end of the four-year period. The amount, if any, ultimately paid to the option holders, including the named executive officers, at the end of the last year of the 2009-2012 performance-measurement period will be based on (1) Southern Company’s average total shareholder return compared to that of its peer companies as of December 31, 2012, (2) the actual dividend paid in 2012 to Southern Company’s stockholders, if any, and (3) the number of options granted prior to 2010 held by the named executive officers on December 31, 2012.

The number of options held on December 31, 2012 will be affected by the number of options exercised by the named executive officers prior to December 31, 2012, if any. None of these components necessary to calculate the range of payout under the Performance Dividend Program for the 2009-2012 performance-measurement period is known at the time the goal is established.

The amounts reported as PDP in columns (c), (d), and (e) were calculated based on the number of options held by the named executive officers on December 31, 2009, as reported in columns (b) and (c) of the Outstanding Equity Awards at Fiscal Year-End table and the Common Stock dividend of $1.73 per share paid to Southern Company’s stockholders in 2009. These factors are itemized below.

		Stock
	Options Held		Performance Dividend				Performance Dividend
	as of		Per Option		Performance Dividend		Per Option Paid at
	December		Paid at Threshold		Per Option Paid at		Maximum
	31, 2009		Performance		Target Performance		Performance
Name	(#)		($)		($)		($)
S. N. Story		266,959		0.04325		0.86500		1.7300
P. C. Raymond		69,759		0.04325		0.86500		1.7300
P. B. Jacob		69,250		0.04325		0.86500		1.7300
T. J. McCullough		47,018		0.04325		0.86500		1.7300
B. C. Terry		58,934		0.04325		0.86500		1.7300

More information about the Performance Dividend Program is provided in the CD&A.

Columns (f) and (g)

The stock options vest at the rate of one-third per year, on the anniversary date of the grant. Also, 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. Please see Potential Payments upon Termination or Change in Control for more information about the treatment of stock options under different termination and change-in-control events.

The Compensation Committee granted these stock options to the named executive officers at its regularly-scheduled meeting on February 19, 2009. Under the terms of the Omnibus Incentive Compensation Plan, the exercise price was set at the closing price ($31.39 per share) on the last trading day prior to the grant date of February 16, 2009.

Column (h)

The value of stock options granted in 2009 was derived using the Black-Scholes stock option pricing model. The assumptions used in calculating these amounts are discussed in Note 8 to the financial statements of Gulf Power in Item 8 herein.

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OUTSTANDING EQUITY AWARDS AT 2009 FISCAL YEAR-END

This table provides information pertaining to all outstanding stock options held by the named executive officers as of December 31, 2009.

											Stock Awards
																	Equity
															Equity		Incentive
															Incentive		Plan
															Plan		Awards:
															Awards:		Market or
	Option Awards										Number				Number		Payout
					Equity						of				of		Value of
					Incentive Plan						Shares		Market		Unearned		Unearned
	Number				Awards:						or Units		Value of		Shares,		Shares,
	of		Number of		Number of						of		Shares or		Units or		Units or
	Securities		Securities		Securities						Stock		Units of		Other		Other
	Underlying		Underlying		Underlying						That		Stock		Rights		Rights
	Unexercised		Unexercised		Unexercised		Option				Have		That Have		That Have		That Have
	Options		Options		Unearned		Exercise		Option		Not		Not		Not		Not
	(#)		(#)		Options		Price		Expiration		Vested		Vested		Vested		Vested
Name	Exercisable		Unexercisable		(#)		($)		Date		(#)		($)		(#)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
S. N. Story		38,529		0		—		32.70		02/18/2015		—		—		—		—
		41,329		0				33.81		02/20/2016
		28,981		14,491				36.42		02/19/2017
		14,469		28,937				35.78		02/18/2018
		0		100,223				31.39		02/16/2019
P. C. Raymond		1,230		0		—		27.98		02/14/2013		—		—		—		—
		4,196		0				29.50		02/13/2014
		9,463		0				32.70		02/18/2015
		8,882		0				33.81		02/20/2016
		6,176		3,088				36.42		02/19/2017
		2,994		5,986				35.78		02/18/2018
		0		27,744				31.39		02/16/2019
P. B. Jacob		4,738		0		—		32.70		02/18/2015		—		—		—		—
		8,825		0				33.81		02/20/2016
		9,283		4,642				36.42		02/19/2017
		4,595		9,190				35.78		02/18/2018
		0		27,977				31.39		02/16/2019
T. J. McCullough		1,985		0		—		27.98		02/14/2013		—		—		—		—
		5,421		0				29.50		02/13/2014
		5,468		0				32.70		02/18/2015
		5,108		0				33.81		02/20/2016
		3,633		1,816				36.42		02/19/2017
		2,924		5,848				35.78		02/18/2018
		0		14,815				31.39		02/16/2019
B. C. Terry		8,905		0		—		33.81		02/20/2016		—		—		—		—
		6,245		3,122				36.42		02/19/2017
		4,306		8,612				35.78		02/18/2018
		0		27,744				31.39		02/16/2019

III-25

Stock options vest one-third per year on the anniversary of the grant date. Options granted from 2002 through 2006 with expiration dates from 2012 through 2016 were fully vested as of December 31, 2009. The options granted in 2007, 2008, and 2009 become fully vested as shown below.

Year Option Granted	Expiration Date	Date Fully Vested
2007	February 19, 2017	February 19, 2010
2008	February 18, 2018	February 18, 2011
2009	February 16, 2019	February 16, 2012

Options also fully vest upon death, total disability, or retirement and expire three years following death or total disability or five years following retirement, or on the original expiration date if earlier. Please see Potential Payments upon Termination or Change in Control for more information about the treatment of stock options under different termination and change-in-control events.

OPTION EXERCISES AND STOCK VESTED IN 2009

None of the named executive officers exercised stock options in 2009 and none were granted Stock Awards.

	Option Awards				Stock Awards
	Number of Shares				Number of Shares
	Acquired on		Value Realized on		Acquired on		Value Realized on
Name	Exercise (#)		Exercise ($)		Vesting (#)		Vesting ($)
(a)	(b)		(c)		(d)		(e)
S. N. Story		0		0		—		—
P. C. Raymond		0		0		—		—
P. B. Jacob		0		0		—		—
T. J. McCullough		0		0		—		—
B. C. Terry		0		0		—		—

PENSION BENEFITS AT 2009 FISCAL YEAR-END

						Payments
		Number of		Present Value of		During
		Years Credited		Accumulated		Last Fiscal
Name	Plan Name	Service (#)		Benefit ($)		Year ($)
(a)	(b)	(c)		(d)		(e)
S. N. Story	Pension Plan		27.00		493,190		0
	SBP-P		27.00		769,884		0
	SERP		27.00		316,861		0
P. C. Raymond	Pension Plan		18.00		285,396		0
	SBP-P		18.00		80,192		0
	SERP		18.00		86,423		0
P. B. Jacob	Pension Plan		26.42		599,150		0
	SBP-P		26.42		194,082		0
	SERP		26.42		158,583		0
T. J. McCullough	Pension Plan		21.75		241,527		0
	SBP-P		21.75		51,546		0
	SERP		21.75		59,008		0
B. C. Terry	Pension Plan		7.50		72,732		0
	SBP-P		7.50		16,383		0
	SERP		7.50		23,438		0

The named executive officers earn employer-paid pension benefits from three coordinated retirement plans. More information about pension benefits is provided in the CD&A.

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Pension Plan

The Pension Plan is a tax-qualified, funded plan. It is Southern Company’s primary retirement plan. Generally, all full-time employees participate in this plan after one year of service. Normal retirement benefits become payable when participants both attain age 65 and complete five years of participation. The plan benefit equals the greater of amounts computed using a “1.7% offset formula” and a “1.25% formula,” as described below. Benefits are limited to a statutory maximum.

The 1.7% offset formula amount equals 1.7% of final average pay times years of participation less an offset related to Social Security benefits. The offset equals a service ratio times 50% of the anticipated Social Security benefits in excess of $4,200. The service ratio adjusts the offset for the portion of a full career that a participant has worked. The highest three rates of pay out of a participant’s last 10 calendar years of service are averaged to derive final average pay. The pay considered for this formula is the base rate of pay reduced for any voluntary deferrals. A statutory limit restricts the amount considered each year; the limit for 2009 was $245,000.

The 1.25% formula amount equals 1.25% of final average pay times years of participation. For this formula, the final average pay computation is the same as above, but annual performance-based compensation paid during each year is added to the base rates of pay.

Early retirement benefits become payable once plan participants have during employment both attained age 50 and completed 10 years of participation. Participants who retire early from active service receive benefits equal to the amounts computed using the same formulas employed at normal retirement. However, a 0.3% reduction applies for each month (3.6% for each year) prior to normal retirement that participants elect to have their benefit payments commence. For example, 64% of the formula benefits are payable starting at age 55. As of December 31, 2009, only Messrs. Jacob and Raymond were eligible to retire immediately.

The Pension Plan’s benefit formulas produce amounts payable monthly over a participant’s post-retirement lifetime. At retirement, plan participants can choose to receive their benefits in one of seven alternative forms of payment. All forms pay benefits monthly over the lifetime of the retiree or the joint lifetimes of the retiree and a spouse. A reduction applies if a retiring participant chooses a payment form other than a single life annuity. The reduction makes the value of the benefits paid in the form chosen comparable to what it would have been if benefits were paid as a single life annuity over the retiree’s life.

Participants vest in the Pension Plan after completing five years of service. All the named executive officers are vested in their Pension Plan benefits. Participants who terminate employment after vesting can elect to have their pension benefits commencing at age 50 if they participated in the Pension Plan for 10 years. If such an election is made, the early retirement reductions that apply are actuarially determined factors and are larger than 0.3% per month.

If a participant dies while actively employed, benefits will be paid to a surviving spouse. A survivor’s benefit equals 45% of the monthly benefit that the participant had earned before his or her death. Payments to a surviving spouse of a participant who could have retired will begin immediately. Payments to a survivor of a participant who was not retirement-eligible will begin when the deceased participant would have attained age 50. After commencing, survivor benefits are payable monthly for the remainder of a survivor’s life. Participants who are eligible for early retirement may opt to have an 80% survivor benefit paid if they die; however, there is a charge associated with this election.

If participants become totally disabled, periods that Social Security or employer-provided disability income benefits are paid will count as service for benefit calculation purposes. The crediting of this additional service ceases at the point a disabled participant elects to commence retirement payments. Outside of the extra service crediting, the normal plan provisions apply to disabled participants.

III-27

The Southern Company Supplemental Benefit Plan (Pension-Related) (SBP-P)

The SBP-P is an unfunded retirement plan that is not tax qualified. This plan provides to high-paid employees any benefits that the Pension Plan cannot pay due to statutory pay/benefit limits and voluntary pay deferrals. The SBP-P’s vesting, early retirement, and disability provisions mirror those of the Pension Plan.

The amounts paid by the SBP-P are based on the additional monthly benefit that the Pension Plan would pay if the statutory limits and pay deferrals were ignored. When an SBP-P participant separates from service, vested monthly benefits provided by the benefit formulas are converted into a single sum value. It equals the present value of what would have been paid monthly for an actuarially determined average post-retirement lifetime. The discount rate used in the calculation is based on the 30-year Treasury yields for the September preceding the calendar year of separation, but not more than six percent. Vested participants terminating prior to becoming eligible to retire will be paid their single sum value as of September 1 following the calendar year of separation. If the terminating participant is retirement eligible, the single sum value will be paid in 10 annual installments starting shortly after separation. The unpaid balance of a retiree’s single sum will be credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a “key man” under Section 409A of the Code, the first installment will be delayed for six months after the date of separation.

If an SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participant’s death occurs prior to age 50, the installments will be paid to a survivor as if the participant had survived to age 50.

The Southern Company Supplemental Executive Retirement Plan (SERP)

The SERP also is an unfunded retirement plan that is not tax qualified. This plan provides to high-paid employees additional benefits that the Pension Plan and the SBP-P would pay if the 1.7% offset formula calculations reflected a portion of annual cash incentives. To derive the SERP benefits, a final average pay is determined reflecting participants’ base rates of pay and their annual performance-based compensation amounts to the extent they exceed 15% of those base rates (ignoring statutory limits and pay deferrals). This final average pay is used in the 1.7% offset formula to derive a gross benefit. The Pension Plan and the SBP-P benefits are subtracted from the gross benefit to calculate the SERP benefit. The SERP’s early retirement, survivor benefit, and disability provisions mirror the SBP-P’s provisions. However, except upon a change in control, SERP benefits do not vest until participants retire, so no benefits are paid if a participant terminates prior to becoming eligible to retire. More information about vesting and payment of SERP benefits following a change in control is included in the section entitled Potential Payments upon Termination or Change in Control.

The following assumptions were used in the present value calculations:

• Discount rate — 5.95% Pension Plan and 5.60% supplemental plans as of December 31, 2009

• Retirement date — Normal retirement age (65 for all named executive officers)

• Mortality after normal retirement — RP2000 Combined Healthy with generational projections

• Mortality, withdrawal, disability, and retirement rates prior to normal retirement — None

• Form of payment for Pension Benefits

o Male retirees: 25% single life annuity; 25% level income annuity; 25% joint and 50% survivor annuity; and 25% joint and 100% survivor annuity

o Female retirees: 40% single life annuity; 40% level income annuity; 10% joint and 50% survivor annuity; and 10% joint and 100% survivor annuity

• Spouse ages — Wives two years younger than their husbands

• Annual performance-based compensation earned but unpaid as of the measurement date — 130% of target opportunity percentages times base rate of pay for year amount is earned.

• Installment determination—4.25% discount rate for single sum calculation and 5.25% prime rate during installment payment period

For all of the named executive officers, the number of years of credited service is one year less than the number of years of employment.

III-28

NONQUALIFIED DEFERRED COMPENSATION AS OF 2009 FISCAL YEAR-END

	Executive		Registrant		Aggregate			Aggregate		Aggregate
	Contributions		Contributions		Earnings			Withdrawals/		Balance
	in Last FY		in Last FY		in Last FY			Distributions		at Last FYE
Name	($)		($)		($)			($)		($)
(a)	(b)		(c)		(d)			(e)		(f)
S. N. Story		0		8,482		22,005			0		1,591,696
P. C. Raymond		0		0		(23	)		0		473
P. B. Jacob		53,655		0		14,824			0		134,565
T. J. McCullough		9,807		0		3,477			0		58,694
B. C. Terry		0		0		2,045			0		68,241

Southern Company provides the DCP which is designed to permit participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement, or other separation from service. Up to 50% of base salary and up to 100% of performance-based compensation, except stock options, may be deferred, at the election of eligible employees. All of the named executive officers are eligible to participate in the DCP.

Participants have two options for the deemed investments of the amounts deferred — the Stock Equivalent Account and the Prime Equivalent Account. Under the terms of the DCP, participants are permitted to transfer between investments at any time.

The amounts deferred in the Stock Equivalent Account are treated as if invested at an equivalent rate of return to that of an actual investment in Common Stock, including the crediting of dividend equivalents as such are paid by Southern Company from time to time. It provides participants with an equivalent opportunity for the capital appreciation (or loss) and income of that of a Southern Company stockholder. During 2009, the rate of return in the Stock Equivalent Account was (4.83%), which was Southern Company’s TSR for 2009.

Alternatively, participants may elect to have their deferred compensation deemed invested in the Prime Equivalent Account which is treated as if invested at a prime interest rate compounded monthly, as published inThe Wall Street Journalas the base rate on corporate loans posted as of the last business day of each month by at least 75% of the United States’ largest banks. The interest rate earned on amounts deferred during 2009 in the Prime Equivalent Account was 3.25%.

Column (b)

This column reports the actual amounts of compensation deferred under the DCP by each named executive officer in 2009. The amount of salary deferred by the named executive officers, if any, is included in the Salary column in the Summary Compensation Table. The amounts of performance-based compensation deferred in 2009 were the amounts paid for performance under the annual Performance Pay Program and the Performance Dividend Program that were earned as of December 31, 2008 but not payable until the first quarter of 2009. These amounts are not reflected in the Summary Compensation Table because that table reports performance-based compensation that was earned in 2009, but not payable until early 2010. These deferred amounts may be distributed in a lump sum or in up to 10 annual installments at termination of employment or in a lump sum at a specified date, at the election of the participant.

Column (c)

This column reflects contributions under the SBP. Under the Code, employer matching contributions are prohibited under the ESP on employee contributions above stated limits in the ESP, and, if applicable, above legal limits set forth in the Code. The SBP is a nonqualified deferred compensation plan under which contributions are made that are prohibited from being made in the ESP. The contributions are treated as if invested in Common Stock and are payable in cash upon termination of employment in a lump sum or in up to 20 annual installments, at the election of

III-29

the participant. The amounts reported in this column also were reported in the All Other Compensation column in the Summary Compensation Table.

Column (d)

This column reports earnings or losses on both compensation the named executive officers elected to defer and on employer contributions under the SBP. See the notes to column (h) of the Summary Compensation Table for a discussion of amounts of nonqualified deferred compensation earnings included in the Summary Compensation Table.

Column (f)

This column includes amounts that were deferred under the DCP and contributions under the SBP in prior years and reported in Gulf Power’s prior years’ Information Statements or Annual Reports on Form 10-K. The chart below shows the amounts reported in Gulf Power’s prior years’ Information Statements or Annual Reports on Form 10-K.

	Amounts Deferred under
	the DCP Prior to 2009		Employer Contributions
	and Reported in Prior		under the SBP Prior to
	Years’ Information		2009 and Reported in Prior Years’
	Statements or Annual		Information Statements or
	Reports on Form 10-K		Annual Reports on Form 10-K		Total
Name	($)		($)		($)
S. N. Story		18,373		266,792		285,165
P. C. Raymond		0		0		0
P. B. Jacob		43,870		22,674		66,544
T. J. McCullough		18,653		0		18,653
B. C. Terry		121,427		0		121,427

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

This section describes and estimates payments that could be made to the named executive officers under different termination and change-in-control events. The estimated payments would be made under the terms of Southern Company’s compensation and benefits programs or the change-in-control severance program. All of the named executive officers are participants in Southern Company’s change-in-control severance plan for officers. The amount of potential payments is calculated as if the triggering events occurred as of December 31, 2009 and assumes that the price of Common Stock is the closing market price on December 31, 2009.

Description of Termination and Change-in-Control Events

The following charts list different types of termination and change-in-control events that can affect the treatment of payments under the compensation and benefit programs. These events also affect payments to the named executive officers under their change-in-control severance agreements. No payments are made under the severance agreements unless, within two years of the change in control, the named executive officer is involuntarily terminated or he or she voluntarily terminates for Good Reason. (See the description of Good Reason below.)

Traditional Termination Events

• Retirement or Retirement Eligible – Termination of a named executive officer who is at least 50 years old and has at least 10 years of credited service.

• Resignation – Voluntary termination of a named executive officer who is not retirement-eligible.

• Lay Off – Involuntary termination of a named executive officer not for cause, who is not retirement-eligible.

III-30

• Involuntary Termination – Involuntary termination of a named executive officer for cause. Cause includes individual performance below minimum performance standards and misconduct, such as violation of Gulf Power’s Drug and Alcohol Policy.

• Death or Disability – Termination of a named executive officer due to death or disability.

Change-in-Control-Related Events

At the Southern Company or Gulf Power level:

• Southern Company Change-in-Control I – Acquisition by another entity of 20% or more of Common Stock, or following a merger with another entity Southern Company’s stockholders own 65% or less of the entity surviving the merger.

• Southern Company Change-in-Control II – Acquisition by another entity of 35% or more of Common Stock, or following a merger with another entity Gulf Power’s stockholders own less than 50% of Gulf Power surviving the merger.

• Southern Company Termination – A merger or other event and Southern Company is not the surviving company or the Common Stock is no longer publicly traded.

• Gulf Power Change in Control – Acquisition by another entity, other than another subsidiary of Southern Company, of 50% or more of the stock of Gulf Power, a merger with another entity and Gulf Power is not the surviving company, or the sale of substantially all the assets of Gulf Power.

At the employee level:

• Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason – Employment is terminated within two years of a change in control, other than for cause, or the employee voluntarily terminates for Good Reason. Good Reason for voluntary termination within two years of a change in control generally is satisfied when there is a material reduction in salary, performance-based compensation opportunity or benefits, relocation of over 50 miles, or a diminution in duties and responsibilities.

III-31

The following chart describes the treatment of different pay and benefit elements in connection with the Traditional Termination Events described above.

		Lay Off
	Retirement/	(Involuntary			Involuntary
	Retirement	Termination			Termination
Program	Eligible	Not For Cause)	Resignation	Death or Disability	(For Cause)
Pension Benefits Plans	Benefits payable as described in the notes following the Pension Benefits table.	Same as Retirement.	Same as Retirement.	Same as Retirement.	Same as Retirement.
Annual Performance Pay Program	Pro-rated if terminate before 12/31.	Same as Retirement.	Forfeit.	Same as Retirement.	Forfeit.
Performance Dividend Program	Paid year of retirement plus two additional years.	Forfeit.	Forfeit.	Payable until options expire or exercised.	Forfeit.
Stock Options	Vest; expire earlier of original expiration date or five years.	Vested options expire in 90 days; unvested are forfeited.	Same as Lay Off.	Vest; expire earlier of original expiration or three years.	Forfeit.
Financial Planning Perquisite	Continues for one year.	Terminates.	Terminates.	Same as Retirement.	Terminates.
Deferred Compensation Plan	Payable per prior elections (lump sum or up to 10 annual installments).	Same as Retirement.	Same as Retirement.	Payable to beneficiary or disabled participant per prior elections; amounts deferred prior to 2005 can be paid as a lump sum per benefit administration committee’s discretion.	Same as Retirement.
Supplemental Benefit Plan – non-pension related	Payable per prior elections (lump sum or up to 20 annual installments).	Same as Retirement.	Same as Retirement.	Same as the Deferred Compensation Plan.	Same as Retirement.

III-32

The chart below describes the treatment of payments under pay and benefit programs under different change-in-control events, except the Pension Plan. The Pension Plan is not affected by change-in-control events.

				Involuntary Change-
				in-Control-Related
				Termination or
			Southern Company	Voluntary Change-
			Termination or Gulf	in-Control-Related
	Southern Company	Southern Company	Power Change in	Termination for
Program	Change-in-Control I	Change-in-Control II	Control	Good Reason
Nonqualified Pension Benefits	All SERP-related benefits vest if participants vested in tax-qualified pension benefits; otherwise, no impact. SBP – pension related benefits vest for all participants and single sum value of benefits earned to change-in-control date paid following termination or retirement.	Benefits vest for all participants and single sum value of benefits earned to the change-in-control date paid following termination or retirement.	Same as Southern Company Change-in-Control II.	Based on type of change-in-control event.
Annual Performance Pay Program	No program termination is paid at greater of target or actual performance. If program terminated within two years of change in control, pro-rated at target performance level.	Same as Southern Company Change-in-Control I.	Pro-rated at target performance level.	If not otherwise eligible for payment, if the program still in effect, pro-rated at target performance level.
Performance Dividend Program	No program termination is paid at greater of target or actual performance. If program terminated within two years of change in control, pro-rated at greater of target or actual performance level.	Same as Southern Company Change-in-Control I.	Pro-rated at greater of actual or target performance level.	If not otherwise eligible for payment, if the program is still in effect, greater of actual or target performance level for year of severance only.
Stock Options	Not affected by change-in-control events.	Not affected by change-in-control events.	Vest and convert to surviving company’s securities; if cannot convert, pay spread in cash.	Vest.
DCP	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.

III-33

				Involuntary Change-
				in-Control-Related
				Termination or
			Southern Company	Voluntary Change-
			Termination or Gulf	in-Control-Related
	Southern Company	Southern Company	Power Change in	Termination for
Program	Change-in-Control I	Change-in-Control II	Control	Good Reason
SBP	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.
Severance Benefits	Not applicable.	Not applicable.	Not applicable.	One or three times base salary plus target annual performance-based compensation plus tax gross up for the president and chief executive officer if the severance amount exceeds the Code Section 280G - “excess parachute payment” by 10% or more.
Health Benefits	Not applicable.	Not applicable.	Not applicable.	Up to five years participation in group health plan plus payment of two or three years’ premium amounts.
Outplacement Services	Not applicable.	Not applicable.	Not applicable.	Six months.

Potential Payments

This section describes and estimates payments that would become payable to the named executive officers upon a termination or change in control as of December 31, 2009.

Pension Benefits

The amounts that would have become payable to the named executive officers if the Traditional Termination Events occurred as of December 31, 2009 under the Pension Plan, the SBP-P, and the SERP are itemized in the chart below. The amounts shown under the column Retirement are amounts that would have become payable to the named executive officers that were retirement-eligible on December 31, 2009 and are the monthly Pension Plan benefits and the first of 10 annual installments from the SBP-P and the SERP. The amounts shown under the column Resignation or Involuntary Termination are the amounts that would have become payable to the named executive officers who were not retirement-eligible on December 31, 2009 and are the monthly Pension Plan benefits that would become payable as of the earliest possible date under the Pension Plan and the single sum value of benefits earned up to the termination date under the SBP-P, paid as a single payment rather than in 10 annual installments. Benefits under the SERP would be forfeited. The amounts shown that are payable to a spouse in the event of the death of the named executive officer are the monthly amounts payable to a spouse under the Pension Plan and the first of 10 annual installments from the SBP-P and the SERP. The amounts in this chart are very different from the pension values shown in the Summary Compensation Table and the Pension Benefits table. Those tables show the

III-34

present values of all the benefits amounts anticipated to be paid over the lifetimes of the named executive officers and their spouses. Those plans are described in the notes following the Pension Benefits table. Of the named executive officers, only Messrs. Jacob and Raymond were retirement eligible on December 31, 2009.

			Resignation or
			Involuntary		Death
	Retirement		Termination		(payments to a spouse)
Name	($)		($)		($)
S. N. Story	Pension	n/a		2,345		3,852
	SBP-P			978,397		110,175
	SERP			0		45,345
P. C. Raymond	Pension	2,345		All plans treated as		2,279
	SBP-P	11,507		retiring		11,507
	SERP	12,401				12,401
P. B. Jacob	Pension	5,162		All plans treated as		3,531
	SBP-P	27,010		retiring		27,010
	SERP	22,069				22,069
T. J. McCullough	Pension	n/a		1,448		2,379
	SBP-P			68,550		8,967
	SERP			0		10,265
B C. Terry	Pension	n/a		619		1,016
	SBP-P			23,643		4,098
	SERP			0		5,863

As described in the Change-in-Control Chart, the only change in the form of payment, acceleration, or enhancement of the pension benefits is that the single sum value of benefits earned up to the change-in-control date under the SBP-P and the SERP could be paid as a single payment rather than in 10 annual installments. Also, the SERP benefits vest for participants who are not retirement-eligible upon a change in control. Estimates of the single sum payment that would have been made to the named executive officers, assuming termination as of December 31, 2009 following a change-in-control event, other than a Southern Company Change-in-Control I (which does not impact how pension benefits are paid), are itemized below. These amounts would be paid instead of the benefits shown in the Traditional Termination Events chart above; they are not paid in addition to those amounts.

	SBP-P		SERP		Total
Name	($)		($)		($)
S. N. Story		954,821		392,976		1,347,797
P. C. Raymond		115,068		124,010		239,078
P. B. Jacob		270,098		220,694		490,792
T. J. McCullough		66,899		76,594		143,493
B. C. Terry		23,073		33,009		56,082

The pension benefit amounts in the tables above were calculated as of December 31, 2009 assuming payments would begin as soon as possible under the terms of the plans. Accordingly, appropriate early retirement reductions were applied. Any unpaid annual performance-based compensation was assumed to be paid at 1.30 times the target level. Pension Plan benefits were calculated assuming each named executive officer chose a single life annuity form of payment, because that results in the greatest monthly benefit. The single sum values of the SBP-P and the SERP benefits were based on a 4.25% discount rate as prescribed by the terms of the plan.

Annual Performance Pay Program

The amount payable if a change in control had occurred on December 31, 2009 is the greater of target or actual performance. Because actual payouts for 2009 performance were below the target level, the amount that would have been payable was the target level amount as reported in the Grants of Plan-Based Awards table.

III-35

Performance Dividends

Because the assumed termination date is December 31, 2009, there is no additional amount that would be payable other than what was reported in the Summary Compensation Table. As described in the Traditional Termination Events chart, there is some continuation of benefits under the Performance Dividend Program for retirees.

However, under the Change-in-Control-Related Events, performance dividends are payable at the greater of target performance or actual performance. For the 2006-2009 performance-measurement period, actual performance exceeded target-level performance.

Stock Options

Stock Options would be treated as described in the Termination and Change-in-Control charts above. Under a Southern Company Termination, all stock options vest. In addition, if there is an Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason, stock options vest. There is no payment associated with stock options unless there is a Southern Company Termination and the participants’ stock options cannot be converted into surviving company stock options. In that event, the excess of the exercise price and the closing price of the Common Stock on December 31, 2009 would be paid in cash for all stock options held by the named executive officers. The chart below shows the number of stock options for which vesting would be accelerated under a Southern Company Termination and the amount that would be payable under a Southern Company Termination if there were no conversion to the surviving company’s stock options.

					Total Payable in
			Total Number of		Cash under a
			Options Following		Southern Company
	Number of Options		Accelerated Vesting		Termination without
	with Accelerated		under a Southern		Conversion of Stock
	Vesting		Company Termination		Options
Name	(#)		(#)		($)
S. N. Story		143,651		266,959		217,318
P. C. Raymond		36,818		69,759		82,010
P. B. Jacob		41,809		69,250		56,934
T. J. McCullough		22,479		47,018		63,291
B. C. Terry		39,478		58,934		53,546

DCP and SBP

The aggregate balances reported in the Nonqualified Deferred Compensation table would be payable to the named executive officers as described in the Traditional Termination and Change-in-Control-Related Events charts above. There is no enhancement or acceleration of payments under these plans associated with termination or change-in-control events, other than the lump-sum payment opportunity described in the above charts. The lump sums that would be payable are those that are reported in the Nonqualified Deferred Compensation table.

Health Benefits

Messrs. Jacob and Raymond are retirement-eligible and health care benefits are provided to retirees, and there is no incremental payment associated with the termination or change-in-control events. At the end of 2009, Mss. Story and Terry and Mr. McCullough were not retirement-eligible and thus health care benefits would not become available until each reaches age 50, except in the case of a change-in-control-related termination, as described in the Change-in-Control-Related Events chart. The estimated cost of providing three years of group health insurance premiums for Ms. Story is $14,000, two years for Ms. Terry is $9,000, and two years for Mr. McCullough is $20,000.

III-36

Financial Planning Perquisite

Since Messrs. Jacob and Raymond are retirement-eligible, an additional year of the Financial Planning perquisite, which is set at a maximum of $8,700 per year, will be provided after retirement. Mss. Story and Terry and Mr. McCullough are not retirement-eligible.

There are no other perquisites provided to the named executive officers under any of the traditional termination or change-in-control-related events.

Severance Benefits

The named executive officers are participants in a change-in-control severance plan. In addition to the treatment of health benefits, the annual Performance Pay Program, and the Performance Dividend Program described above, the named executive officers are entitled to a severance benefit, including outplacement services, if within two years of a change in control, they are involuntarily terminated, not for Cause, or they voluntarily terminate for Good Reason. The severance benefits are not paid unless the named executive officer releases the employing company from any claims he or she may have against the employing company.

The estimated cost of providing the six months of outplacement services is $6,000 per named executive officer. The severance payment is three times the base salary and target payout under the annual Performance Pay Program for Ms. Story and one times the base salary and target payout under the annual Performance Pay Program for the other named executive officers. For Ms. Story, if any portion of the severance payment is an “excess parachute payment” as defined under Section 280G of the Code, Gulf Power will pay her an additional amount to cover the taxes that would be due on the excess parachute payment — a “tax gross-up.” However, that additional amount will not be paid unless the severance amount plus all other amounts that are considered parachute payments under the Code exceed 110% of the severance payment.

The table below estimates the severance payments that would be made to the named executive officers if they were terminated as of December 31, 2009 in connection with a change in control. There is no estimated tax gross-up included for Ms. Story because her estimated severance amount payable is below the amount considered excess parachute payments under the Code. None of the other named executive officer is eligible for a tax gross-up.

Name	Severance Amount ($)
S. N. Story		1,901,202
P. C. Raymond		331,228
P. B. Jacob		334,002
T. J. McCullough		256,162
B. C. Terry		331,228

COMPENSATION RISK ASSESSMENT

Southern Company reviewed its compensation policies and practices, including those of Gulf Power, and concluded that excessive risk-taking is not encouraged. This conclusion was based on an assessment of the mix of pay components and performance goals, the annual pay/performance analysis by the Compensation Committee’s consultant, stock ownership requirements, our compensation governance practices, and our “claw-back” provision.

The assessment was reviewed with the Compensation Committee.

III-37

DIRECTOR COMPENSATION

Only non-employee directors of Gulf Power are compensated for service on the board of directors. The pay components for non-employee directors are:

     Annual retainers:

• $12,000 annual retainer

     Equity grants:

• 340 shares of Common Stock in quarterly grants of 85 shares

     Meeting fees:

• $1,200 for participation in a meeting of the board

• $1,000 for participation in a meeting of a committee of the board

DIRECTOR DEFERRED COMPENSATION PLAN

Any deferred quarterly equity grants are required to be deferred in the Deferred Compensation Plan For Directors of Gulf Power Company (Director Deferred Compensation Plan) and are invested in Common Stock units which earn dividends as if invested in Common Stock. Earnings are reinvested in additional stock units. Upon leaving the board, distributions are made in shares of Common Stock.

In addition, directors may elect to defer up to 100% of their remaining compensation in the Director Deferred Compensation Plan until membership on the board ends. Deferred compensation may be invested as follows, at the director’s election:

• in Common Stock units which earn dividends as if invested in Common Stock and are distributed in shares of Common Stock upon leaving the board

• in Common Stock units which earn dividends as if invested in Common Stock and are distributed in cash upon leaving the board

• at prime interest which is paid in cash upon leaving the board

All investments and earnings in the Director Deferred Compensation Plan are fully vested and, at the election of the director, may be distributed in a lump sum payment or in up to 10 annual distributions after leaving the board.

III-38

DIRECTOR COMPENSATION TABLE

The following table reports all compensation to Gulf Power’s non-employee directors during 2009, including amounts deferred in the Director Deferred Compensation Plan. Non-employee directors do not receive Non-Equity Incentive Plan Compensation, and there is no pension plan for non-employee directors.

					Change in
					Pension
					Value and
					Nonqualified
					Deferred
	Fees Earned or Paid		Stock		Compensation		All Other
	in Cash		Awards		Earnings		Compensation		Total
Name	($)(1)		($)(2)		($)(3)		($)(4)		($)
C. LeDon Anchors		16,800		17,127		0		54		33,981
William C. Cramer, Jr.		0		33,927		0		54		33,981
Fred C. Donovan, Sr.		0		33,927		0		54		33,981
William A. Pullum		0		33,927		0		54		33,981
Winston E. Scott		33,858		0		0		3,866		37,724

(1)	Includes amounts voluntarily deferred in the Director Deferred Compensation Plan.
(2)	Includes fair market value of equity grants on grant dates. All such stock awards are vested immediately upon grant.
(3)	Above-market earnings on amounts invested in the Director Deferred Compensation Plan. Above-market earnings are defined by the SEC as any amount above 120% of the applicable federal long-term rate as prescribed under Section 1274(d) of the Code.
(4)	Consists of reimbursement for taxes on imputed income associated with gifts.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Compensation Committee is made up of non-employee directors of Southern Company who have never served as executive officers of Southern Company or Gulf Power. During 2009, none of Southern Company’s or Gulf Power’s executive officers served on the board of directors of any entities whose directors or officers serve on the Compensation Committee.

III-39

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 Gulf Power.

		Amount and
	Name and Address	Nature of		Percent
	of Beneficial	Beneficial		of
Title of Class	Owner	Ownership		Class
Common Stock	The Southern Company
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308				100	%
	Registrant:
	Gulf Power		3,642,717

Security Ownership of Management.The following tables show the number of shares of Common Stock owned by the directors, nominees, and executive officers as of December 31, 2009. 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, 2009.

			Shares Beneficially Owned Include:
					Shares
					Individuals
					Have Rights
Name of Directors,	Shares				to Acquire
Nominees, and	Beneficially		Deferred Stock		Within 60
Executive Officers	Owned (1)		Units (2)		Days (3)
Susan N. Story		191,938		0		185,675
C. LeDon Anchors		7,492		5,751		0
William C. Cramer, Jr.		9,115		9,115		0
Fred C. Donovan, Sr.		6,338		6,338		0
William A. Pullum		10,458		10,458		0
Winston E. Scott		1,407		0		0
P. Bernard Jacob		52,275		0		46,004
Theodore J. McCullough		34,887		0		34,218
Philip C. Raymond		50,615		0		48,270
Bentina C. Terry		37,458		0		36,162
Directors, Nominees, and Executive Officers as a group (10 people)		401,983		31,662		350,329

(1)	“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 or any combination thereof.
(2)	Indicates the number of deferred stock units held under the Director Deferred Compensation Plan.
(3)	Indicates shares of Common Stock that certain executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column.

Changes in Control.Southern Company and Gulf Power know of no arrangements which may at a subsequent date result in any change-in-control.

III-40

Equity Compensation Plan Information

The following table provides information as of December 31, 2009 concerning shares of Common Stock authorized for issuance under Southern Company’s existing non-qualified equity compensation plans.

					Number of securities
					remaining available
					for future issuance
					under equity
	Number of securities		Weighted-average		compensation plans
	to be issued upon		exercise price of		(excluding
	exercise of		outstanding		securities
	outstanding options,		options, warrants,		reflected in
	warrants, and rights		and rights		column (a))
Plan category	(a)		(b)		(c)
Equity compensation plans approved by security holders		48,247,319	$	32.10		22,497,013
Equity compensation plans not approved by security holders		N/A		N/A		N/A

(1)	Includes shares available for future issuances under the Omnibus Incentive Compensation Plan, the 2006 Omnibus Incentive Compensation Plan, and the Outside Directors Stock Plan.
(2)	Includes shares available for future issuance under the 2006 Omnibus Incentive Compensation Plan (20,985,906) and the Outside Directors Stock Plan (1,511,107).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Transactions with Related Persons.None.

Review, Approval or Ratification of Transactions with Related Persons.

Gulf Power does not have a written policy pertaining solely to the approval or ratification of “related party transactions.” Southern Company has a Code of Ethics as well as a Contract Guidance Manual and other formal written procurement policies and procedures that guide the purchase of goods and services, including requiring competitive bids for most transactions above $10,000 or approval based on documented business needs for sole sourcing arrangements.

III-41

Director Independence.

The board of directors of Gulf Power consists of five non-employee directors (Messrs. C. LeDon Anchors, William C. Cramer, Jr., Fred C. Donovan, Sr., William A. Pullum, and Winston E. Scott) and Ms. Story, the president and chief executive officer of Gulf Power.

Southern Company owns all of Gulf Power’s outstanding common stock. Gulf Power has listed only debt securities on the NYSE. Accordingly, under the rules of the NYSE, Gulf Power is exempt from most of the NYSE’s listing standards relating to corporate governance, including requirements relating to certain board committees. Gulf Power has voluntarily complied with certain of the NYSE’s listing standards relating to corporate governance where such compliance was deemed to be in the best interests of Gulf Power’s shareholders.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following represents the fees billed to Gulf Power and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company’s principal public accountant for 2009 and 2008:

	2009		2008
	(in thousands)
Gulf Power
Audit Fees (1)	$	1,308	$	1,324
Audit-Related Fees		0		0
Tax Fees		0		0
All Other Fees		0		0
Total	$	1,308	$	1,324
Southern Power
Audit Fees (1)	$	1,136	$	943
Audit-Related Fees (2)		38		0
Tax Fees		0		0
All Other Fees		0		0
Total	$	1,174	$	943

(1)	Includes services performed in connection with financing transactions.
(2)	Includes other non-statutory audit services and accounting consultations.

The Southern Company Audit Committee (on behalf of Southern Company and 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 2009 and 2008 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.

III-42

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report on Form 10-K:

(1)	Financial Statements:
	Management’s Report on Internal Control Over Financial Reporting for Southern Company and Subsidiary Companies is listed under Item 8 herein.
	Management’s Report on Internal Control Over Financial Reporting for Alabama Power is listed under Item 8 herein.
	Management’s Report on Internal Control Over Financial Reporting for Georgia Power is listed under Item 8 herein.
	Management’s Report on Internal Control Over Financial Reporting for Gulf Power is listed under Item 8 herein.
	Management’s Report on Internal Control Over Financial Reporting for Mississippi Power is listed under Item 8 herein.
	Management’s Report on Internal Control Over Financial Reporting for Southern Power 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, and Southern Power and Subsidiary Companies 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, and Southern Power and Subsidiary Companies 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, and Mississippi Power are included herein on pages IV-8, IV-9, IV-10, IV-11, and IV-12.
	Financial Statement Schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, and Mississippi 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, 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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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)
W. Paul Bowers
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
W. Ron Hinson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Juanita Powell Baranco		Warren A. Hood, Jr.
Jon A. Boscia		Donald M. James
Thomas F. Chapman		J. Neal Purcell
Henry A. Clark III		William G. Smith, Jr.
H. William Habermeyer, Jr.		Gerald J. St. Pé
Veronica M. Hagen
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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)
Moses H. Feagin
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Whit Armstrong		Robert D. Powers
Ralph D. Cook		David M. Ratcliffe
David J. Cooper, Sr.		C. Dowd Ritter
John D. Johns		James H. Sanford
Patricia M. King		John Cox Webb, IV
James K. Lowder		James W. Wright
Malcolm Portera
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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)
Ronnie R. Labrato
Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
Ann P. Daiss
Vice President, Comptroller, and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Robert L. Brown, Jr.		Beverly D. Tatum
Anna R. Cablik		D. Gary Thompson
Stephen S. Green		Richard W. Ussery
David M. Ratcliffe		W. Jerry Vereen
Jimmy C. Tallent		E. Jenner Wood, III
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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)
Philip C. Raymond
Vice President and Chief Financial Officer
(Principal Financial Officer)
Constance J. Erickson
Comptroller
(Principal Accounting Officer)
Directors:
C. LeDon Anchors		William A. Pullum
William C. Cramer, Jr.		Winston E. Scott
Fred C. Donovan, Sr.
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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 Turnage
Vice President, Treasurer, and Chief Financial Officer
(Principal Financial Officer)
Cindy F. Shaw
Comptroller
(Principal Accounting Officer)
Directors:
Roy Anderson, III		Christine L. Pickering
Carl J. Chaney		Philip J. Terrell
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

IV-6

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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

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 Officer)
Laura I. Patterson
Comptroller
(Principal Accounting Officer)
Directors:
W. Paul Bowers		G. Edison Holland
Thomas A. Fanning		David M. Ratcliffe
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date: February 25, 2010

IV-7

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 Subsidiaries (the “Company”) as of December 31, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and the Company’s internal control over financial reporting as of December 31, 2009, and have issued our report thereon dated February 25, 2010; such report is 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 25, 2010

Member of

Deloitte Touche Tohmatsu

IV-8

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, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and have issued our report thereon dated February 25, 2010; such report is 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 25, 2010

Member of

Deloitte Touche Tohmatsu

IV-9

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, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and have issued our report thereon dated February 25, 2010; such report is 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 25, 2010

Member of

Deloitte Touche Tohmatsu

IV-10

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, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and have issued our report thereon dated February 25, 2010; such report is 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 25, 2010

Member of

Deloitte Touche Tohmatsu

IV-11

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, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and have issued our report thereon dated February 25, 2010; such report is 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 25, 2010

Member of                            
Deloitte Touche Tohmatsu

IV-12

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule II	Page
Valuation and Qualifying Accounts and Reserves 2009, 2008, and 2007
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

Schedules I through V not listed above are omitted as not applicable or not required. A Schedule II for Southern Power Company and Subsidiary Companies is not being provided because there were no reportable items for the three-year period ended December 31, 2009. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.

S-1

Schedule Of Valuation And Qualifying Accounts Disclosure

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007
(Stated in Thousands of Dollars)

	Balance		Additions
	at Beginning		Charged to		Charged to					Balance at End
Description	of Period		Income		Other Accounts		Deductions			of Period
Provision for uncollectible accounts
2009	$	26,326	$	58,722	$	—	$	60,480	(Note)	$	24,568
2008		22,142		60,184		—		56,000	(Note)		26,326
2007		34,901		34,471		—		47,230	(Note)		22,142

(Note) 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, 2009, 2008, AND 2007
(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
2009	$	8,882	$	21,951	$	—	$21,282 (Note)	$	9,551
2008		7,988		20,824		—	19,930 (Note)		8,882
2007		7,091		16,678		—	15,781 (Note)		7,988

(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, 2009, 2008, AND 2007
(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
2009	$	10,732	$	29,088	$	—	$29,964 (Note)	$	9,856
2008		7,636		31,219		—	28,123 (Note)		10,732
2007		10,030		20,336		—	22,730 (Note)		7,636

(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, 2009, 2008, AND 2007
(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
2009	$	2,188	$	3,753	$	—	$4,028 (Note)	$	1,913
2008		1,711		3,893		—	3,416 (Note)		2,188
2007		1,279		3,315		—	2,883 (Note)		1,711

(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, 2009, 2008, AND 2007
(Stated in Thousands of Dollars)

			Additions
	Balance at		Charged		Charged to			Balance at
	Beginning		to		Other			End
Description	of Period		Income		Accounts		Deductions	of Period
Provision for uncollectible accounts
2009	$	1,039	$	2,356	$	—	$2,455 (Note)	$	940
2008		924		2,372		—	2,257 (Note)		1,039
2007		855		1,896		—	1,827 (Note)		924

(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

S-6

EXHIBIT INDEX

     The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements required to be identified as such by Item 15 of Form 10-K.

(3)	Articles of Incorporation and By-Laws
	Southern Company
		(a)	1	-	Composite Certificate of Incorporation of Southern Company, reflecting all amendments thereto through January 5, 1994. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A, and in Certificate of Notification, File No. 70-8181, as Exhibit A.)
		(a)	2	-	By-laws of Southern Company as amended effective February 17, 2003, and as presently in effect. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3526, as Exhibit 3(a)1.)
	Alabama Power
		(b)	1	-	Charter of Alabama Power and amendments thereto through April 25, 2008. (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, in Form 8-K dated February 5, 2004, File No. 1-3164, as Exhibit 4.4, in Alabama Power’s Form 10-Q for the quarter ended March 31, 2006, File No. 1-3164, as Exhibit 3(b)(1), in Form 8-K dated December 5, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 12, 2007, File No. 1-3164, as Exhibit 4.5, in Form 8-K dated October 17, 2007, File No. 1-3164, as Exhibit 4.5, and in Alabama Power’s Form 10-Q for the quarter ended March 31, 2008, File No. 1-3164, as Exhibit 3(b)1.)
		(b)	2	-	By-laws of Alabama Power as amended effective January 26, 2007, and as presently in effect. (Designated in Form 8-K dated January 26, 2007, File No 1-3164, as Exhibit 3(b)2.)
	Georgia Power
		(c)	1	-	Charter of Georgia Power and amendments thereto through October 9, 2007. (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

E-1

				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, in Georgia Power’s Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2, in Form 8-K dated June 27, 2006, File No. 1-6468, as Exhibit 3.1, and in Form 8-K dated October 3, 2007, File No. 1-6468, as Exhibit 4.5.)
	(c)	2	-	By-laws of Georgia Power as amended effective May 20, 2009, and as presently in effect. (Designated in Form 8-K dated May 20, 2009, 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 October 17, 2007. (Designated in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 3.1, in Form 8-K dated November 9, 2005, File No. 0-2429, as Exhibit 4.7, and in Form 8-K dated October 16, 2007, File No. 0-2429, as Exhibit 4.5.)
	(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 Form 8-K dated March 3, 2004, File No. 0-6849, as Exhibit 4.6.)
	(e)	2	-	By-laws of Mississippi Power as amended effective February 28, 2001, and as presently in effect. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2001, File No. 0-6849, as Exhibit 3(e)2.)
Southern Power
	(f)	1	-	Certificate of Incorporation of Southern Power dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)
	(f)	2	-	By-laws of Southern Power effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)

E-2

(4)	Instruments Describing Rights of Security Holders, Including Indentures
	Southern Company
		(a)	1	-	Senior Note Indenture dated as of February 1, 2002, among Southern Company, Southern Company Capital Funding, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank)), 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 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)	2	-	Senior Note Indenture dated as of January 1, 2007, between Southern Company and Wells Fargo Bank, National Association, as Trustee, and indentures supplemental thereto through October 22, 2009. (Designated in Form 8-K dated January 11, 2006, File No. 1-3526, as Exhibits 4.1 and 4.2, in Form 8-K dated March 20, 2007, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated August 13, 2008, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated May 11, 2009, File No. 1-3526, as Exhibit 4.2, and in Form 8-K dated October 19, 2009, File No. 1-3526, as Exhibit 4.2.)
	Alabama Power
		(b)	1	-	Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as 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)	2	-	Senior Note Indenture dated as of December 1, 1997, between Alabama Power and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank)), as Trustee, and indentures supplemental thereto through March 6, 2009. (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

E-3

				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, in Form 8-K dated February 1, 2006, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 9, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated June 7, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 30, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 4, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 11, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated December 4, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 8, 2008, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14, 2008, File No. 1-3164 as Exhibit 4.2, and in Form 8-K dated February 26, 2009, File No. 1-3164 as Exhibit 4.2.)
	(b)	3	-	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)	4	-	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 The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as 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 The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank)), as Trustee, and indentures supplemental thereto through December 15, 2009. (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, in Form 8-K dated November 30, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated December 8, 2006, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 6, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 4, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 18, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated July 10, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated August 24, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 29, 2007, File No. 1-6468, as Exhibit 4.2, in

E-4

				Form 8-K dated March 12, 2008, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 5, 2008, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 12, 2008, File No. 1-6468, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 4, 2009, File No. 1-6468, as Exhibit 4.2, and in Form 8-K dated December 8, 2009, File No. 1-6468, as Exhibit 4.2.)
	(c)	3	-	Senior Note Indenture dated as of March 1, 1998 between Georgia Power, as successor to Savannah Electric, and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank)), as Trustee, and indentures supplemental thereto through June 30, 2006. (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, in Form 8-K dated December 2, 2004, File No. 1-5072, as Exhibit 4.1, and in Form 8-K dated June 27, 2006, File No. 1-6468, as Exhibit 4.2.)
	(c)	4	-	Amended and Restated Trust Agreement of Georgia Power Capital Trust VII dated as of January 1, 2004. (Designated in Form 8-K dated January 15, 2004, as Exhibit 4.7-A.)
	(c)	5	-	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	-	Senior Note Indenture dated as of January 1, 1998, between Gulf Power and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A. (formerly known as The Chase Manhattan Bank)), as Trustee, and indentures supplemental thereto through June 26, 2009. (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, in Form 8-K dated October 27, 2005, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated November 28, 2006, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated June 5, 2007, File No. 0-2429, as Exhibit 4.2, and in Form 8-K dated June 22, 2009, File No. 0-2429, as Exhibit 4.2.)
Mississippi Power
	(e)	1	-	Senior Note Indenture dated as of May 1, 1998 between Mississippi Power and Wells Fargo Bank, National Association, as Successor Trustee, and indentures supplemental thereto through March 6, 2009. (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, in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated November 8, 2007, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated November 14, 2008, File No. 001-11229, as Exhibit 4.2, and in Form 8-K dated March 3, 2009, File No. 001-11229, as Exhibit 4.2.)

E-5

	Southern Power
			(f)	1	-	Senior Note Indenture dated as of June 1, 2002, between Southern Power and The Bank of New York Mellon (formerly known as The Bank of New York), as Trustee, and indentures supplemental thereto through November 21, 2006. (Designated in Registration No. 333-98553 as Exhibits 4.1 and 4.2 and in Southern Power’s Form 10-Q for the quarter ended June 30, 2003, File No. 333-98553, as Exhibit 4(g)1, and in Form 8-K dated November 13, 2006, File No. 333-98553, as Exhibit 4.2.)
(10)	Material Contracts Southern Company
	#		(a)	1	-	Amended and Restated Southern Company Omnibus Incentive Compensation Plan, effective January 1, 2007. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)1.)
	#		(a)	2	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. (Designated in Southern Company’s Form 10-Q for the quarter ended March 31, 2009, File No. 1-3526, as Exhibit 10(a)1.)
	#		(a)	3	-	Deferred Compensation Plan for Directors of The Southern Company, Amended and Restated effective January 1, 2008. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2007, File No. 1-3536, as Exhibit 10(a)3.)
	#		(a)	4	-	Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)4.)
	#	*	(a)	5	-	First Amendment effective January 1, 2010 to the Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009.
	#		(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 January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)6.)
	#	*	(a)	8	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009.
	#		(a)	9	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)7.)
	#	*	(a)	10	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009.
	#		(a)	11	-	Amended and Restated Change in Control Agreement dated December 31, 2008 between Southern Company, Alabama Power, and Charles D. McCrary. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)9.)

E-6

#	(a)	12	-	Amended and Restated Change in Control Agreement dated December 31, 2008 between Southern Company, SCS, and David M. Ratcliffe. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)10.)
#	(a)	13	-	The Southern Company Change in Control Benefits Protection Plan, effective December 31, 2008. (Designated in Form 8-K dated December 31, 2008, File No. 1-3526, as Exhibit 10.1.)
	(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, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103 and in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)16.)
#	(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, and Mississippi Power and First Amendment thereto effective January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)104 and in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)18.)
#	(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, and Mississippi Power and First Amendment thereto effective January 1, 2009. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)92 and in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)20.)
#	(a)	20	-	Amended and Restated Change in Control Agreement effective December 31, 2008 between Southern Company, SCS, and Thomas A. Fanning. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)21.)
#	(a)	21	-	Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)23.)

E-7

#	*	(a)	22	-	First Amendment effective January 1, 2010 to the Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008.
#		(a)	23	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)24.)
#	*	(a)	24	-	First Amendment effective January 1, 2010 to the Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008.
#		(a)	25	-	Amended and Restated Change in Control Agreement effective December 31, 2008 between Southern Company, Georgia Power, and Michael D. Garrett. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)25.)
#		(a)	26	-	Amended and Restated Change in Control Agreement effective December 31, 2008 between Southern Company, SCS, and William Paul Bowers. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2008, File No. 1-3536, as Exhibit 10(a)26.)
#		(a)	27	-	Form of Restricted Stock Award Agreement. (Designated in Form 10-Q for the quarter ended September 30, 2007, File No. 1-3526, as Exhibit 10(a)1.)
#	*	(a)	28	-	Base Salaries of Named Executive Officers.
#		(a)	29	-	Summary of Non-Employee Director Compensation Arrangements. (Designated in Form 10-K for the year ended December 31, 2007, File No. 1-3526, as Exhibit 10(a)27.)
#		(a)	30	-	Form of Terms for Performance Share Awards granted under the Southern Company Omnibus Incentive Compensation Plan. (Designated in Form 8-K dated February 9, 2010, File No. 1-3526, as Exhibit 10.1.)
Alabama Power
		(b)	1	-	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and SCS. (Designated in Form 10-Q for the quarter ended March 31, 2007, File No. 1-3164, as Exhibit 10(b)5.)
#		(b)	2	-	Amended and Restated Southern Company Omnibus Incentive Compensation Plan, effective January 1, 2007. See Exhibit 10(a)1 herein.
#		(b)	3	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#		(b)	4	-	Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. See Exhibit 10(a)4 herein.
#		(b)	5	-	First Amendment effective January 1, 2010 to the Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. 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-8

#	(b)	7	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)7 herein.
#	(b)	8	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)8 herein.
#	(b)	9	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)9 herein.
#	(b)	10	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)10 herein.
#	(b)	11	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)23 herein.
#	(b)	12	-	First Amendment effective January 1, 2010 to the Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)24 herein.
#	(b)	13	-	Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated effective January 1, 2008. (Designated in Alabama Power’s Form 10-Q for the quarter ended June 30, 2008, File No. 1-3164, as Exhibit 10(b)1.)
#	(b)	14	-	The Southern Company Change in Control Benefits Protection Plan, effective December 31, 2008. See Exhibit 10(a)13 herein.
#	(b)	15	-	Southern Company Deferred Compensation Trust Agreement as amended and restated effective January 1, 2001 between Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)17 herein.
#	(b)	16	-	Deferred Stock Trust Agreement for Directors of Southern Company and its subsidiaries, dated as of January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)18 herein.
#	(b)	17	-	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its subsidiaries, effective September 1, 2001, between Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)19 herein.
#	(b)	18	-	Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)21 herein.
#	(b)	19	-	First Amendment effective January 1, 2010 to the Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)22 herein.
#	(b)	20	-	Amended and Restated Change in Control Agreement dated December 31, 2008 between Southern Company, Alabama Power, and Charles D. McCrary. See Exhibit 10(a)11 herein.

E-9

#	*	(b)	21	-	Deferred Compensation Agreement between Southern Company, Alabama Power, and SCS and Mark A. Crosswhite dated July 30, 2008.
#	*	(b)	22	-	Base Salaries of Named Executive Officers.
#		(b)	23	-	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.)
#		(b)	24	-	Form of Restricted Stock Award Agreement. See Exhibit 10(a)27 herein.
#		(b)	25	-	Form of Terms for Performance Share Awards granted under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)30 herein.
Georgia Power
		(c)	1	-	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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	-	Amended and Restated Southern Company Omnibus Incentive Compensation Plan, effective January 1, 2007. See Exhibit 10(a)1 herein.
#		(c)	6	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#		(c)	7	-	Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. See Exhibit 10(a)4 herein.
#		(c)	8	-	First Amendment effective January 1, 2010 to the Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. 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 January 1, 2009. See Exhibit 10(a)7 herein.
#		(c)	11	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)8 herein.

E-10

#		(c)	12	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)9 herein.
#		(c)	13	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)10 herein.
#		(c)	14	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)23 herein.
#		(c)	15	-	First Amendment effective January 1, 2010 to the Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)24 herein.
#		(c)	16	-	Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective January 1, 2008. (Designated in Form 10-K for the year ended December 31, 2007, File No. 1-6468, as Exhibit 10(c)12.)
#		(c)	17	-	The Southern Company Change in Control Benefits Protection Plan, effective December 31, 2008. See Exhibit 10(a)13 herein.
#		(c)	18	-	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, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)17 herein.
#		(c)	19	-	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)18 herein.
#		(c)	20	-	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)19 herein.
#		(c)	21	-	Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)21 herein.
#		(c)	22	-	First Amendment effective January 1, 2010 to the Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)22 herein.
#	*	(c)	23	-	Consulting Agreement between Cliff S. Thrasher and Georgia Power dated March 18, 2009.
#		(c)	24	-	Amended and Restated Change in Control Agreement effective December 31, 2008 between Southern Company, Georgia Power, and Michael D. Garrett. See Exhibit 10(a)25 herein.
#	*	(c)	25	-	Base Salaries of Named Executive Officers.
#	*	(c)	26	-	Summary of Non-Employee Director Compensation Arrangements.
#		(c)	27	-	Form of Restricted Stock Award Agreement. See Exhibit 10(a)27 herein.

E-11

		(c)	28	-	Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for OPC, MEAG Power, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Georgia Power requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.) (Designated in Form 10-Q/A for the quarter ended June 30, 2008, File No. 1-6468, as Exhibit 10(c)1.)
	*	(c)	29	-	Amendment No. 1, dated as of December 11, 2009, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for OPC, MEAG Power, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power has omitted such portions from the filing and filed them separately with the SEC.)
#		(c)	30	-	Form of Terms for Performance Share Awards granted under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)30 herein.
Gulf Power
		(d)	1	-	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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, 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, 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 Jacksonville Electric Authority and Alabama Power, Georgia Power, Gulf Power, Mississippi Power, 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	-	Amended and Restated Southern Company Omnibus Incentive Compensation Plan, effective January 1, 2007. See Exhibit 10(a)1 herein.
#		(d)	6	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#		(d)	7	-	Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. See Exhibit 10(a)4 herein.
#		(d)	8	-	First Amendment effective January 1, 2010 to the Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. See Exhibit 10(a)5 herein.

E-12

#		(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 as of January 1, 2009. See Exhibit 10(a)9 herein.
#		(d)	11	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)10 herein.
#		(d)	12	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)23 herein.
#		(d)	13	-	First Amendment effective January 1, 2010 to the Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)24 herein.
#		(d)	14	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)7 herein.
#		(d)	15	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)8 herein.
#		(d)	16	-	Deferred Compensation Plan For Outside Directors of Gulf Power Company, Amended and Restated effective January 1, 2008. (Designated in Gulf Power’s Form 10-Q for the quarter ended March 31, 2008, File No. 0-2429, as Exhibit 10(d)1.)
#		(d)	17	-	The Southern Company Change in Control Benefits Protection Plan, effective December 31, 2008. See Exhibit 10(a)13 herein.
#		(d)	18	-	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, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)17 herein.
#		(d)	19	-	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)18 herein.
#		(d)	20	-	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)19 herein.
#		(d)	21	-	Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)21 herein.
#		(d)	22	-	First Amendment effective January 1, 2010 to the Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)22 herein.
#	*	(d)	23	-	Base Salaries of Named Executive Officers.

E-13

#	(d)	24	-	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.)
#	(d)	25	-	Form of Restricted Stock Award Agreement. See Exhibit 10(a)27 herein.
	(d)	26	-	Power Purchase Agreement between Gulf Power and Shell Energy North America (US), L.P. dated March 16, 2009. (Designated in Gulf Power’s Form 10-Q for the quarter ended March 31, 2009, File No. 0-2429, as Exhibit 10(d)1.) (Gulf Power requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Gulf Power omitted such portions from this filing and filed them separately with the SEC.)
#	(d)	27	-	Form of Terms for Performance Share Awards granted under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)30 herein.
Mississippi Power
	(e)	1	-	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and SCS. See Exhibit 10(b)1 herein.
	(e)	2	-	Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 1981, File No. 0-6849, as Exhibit 10(f), in Mississippi Power’s Form 10-K for the year ended December 31, 1982, File No. 0-6849, as Exhibit 10(f)(2), and in Mississippi Power’s Form 10-K for the year ended December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
#	(e)	3	-	Amended and Restated Southern Company Omnibus Incentive Compensation Plan, effective January 1, 2007. See Exhibit 10(a)1 herein.
#	(e)	4	-	Form of 2009 Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	(e)	5	-	Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. See Exhibit 10(a)4 herein.
#	(e)	6	-	First Amendment effective January 1, 2010 to the Southern Company Deferred Compensation Plan as amended and restated as of January 1, 2009. 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 as of January 1, 2009. See Exhibit 10(a)9 herein.
#	(e)	9	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009. See Exhibit 10(a)10 herein.

E-14

#		(e)	10	-	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)23 herein.
#		(e)	11	-	First Amendment effective January 1, 2010 to the Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008. See Exhibit 10(a)24 herein.
#		(e)	12	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)7 herein.
#		(e)	13	-	First Amendment effective January 1, 2010 to The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009. See Exhibit 10(a)8 herein.
#		(e)	14	-	Deferred Compensation Plan for Outside Directors of Mississippi Power Company, Amended and Restated effective January 1, 2008. (Designated in Mississippi Power’s Form 10-Q for the quarter ended March 31, 2008, File No. 0-6849 as Exhibit 10(e)1.)
#		(e)	15	-	The Southern Company Change in Control Benefits Protection Plan, effective December 31, 2008. See Exhibit 10(a)13 herein.
#		(e)	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, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)17 herein.
#		(e)	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)18 herein.
#		(e)	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, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)19 herein.
#		(e)	19	-	Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)21 herein.
#		(e)	20	-	First Amendment effective January 1, 2010 to the Amended and Restated Southern Company Senior Executive Change in Control Severance Plan effective December 31, 2008. See Exhibit 10(a)22 herein.
#	*	(e)	21	-	Base Salaries of Named Executive Officers.
#	*	(e)	22	-	Summary of Non-Employee Director Compensation Arrangements.
#		(e)	23	-	Form of Restricted Stock Award Agreement. See Exhibit 10(a)27 herein.
		(e)	24	-	Cooperative Agreement between the DOE and SCS dated as of December 12, 2008. (Designated in Mississippi Power’s Form 10-K for the year ended December 31, 2008, File No. 001-11229, as Exhibit 10(e)22.) (Mississippi Power requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Mississippi Power omitted such portions from this filing and filed them separately with the SEC.)

E-15

#	(e)	25	-	Form of Terms for Performance Share Awards granted under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)30 herein.
Southern Power
	(f)	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).)
	(f)	2	-	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and SCS. See Exhibit 10(b)1 herein.
	(f)	3	-	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.)
	(f)	4	-	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.)
	(f)	5	-	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.)
	(f)	6	-	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)
	(f)	7	-	Multi-Year Credit Agreement dated as of July 7, 2006 by and among Southern Power, the Lenders (as defined therein), Citibank, N.A., as Administrative Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Initial Issuing Bank and Amendment Number One thereto. (Designated in Southern Power’s Form 10-Q for the quarter ended June 30, 2006, File No. 333-98553, as Exhibit 10(f)1 and in Form 10-Q for the quarter ended June 30, 2007, File No. 333-98553, as Exhibit 10(f)2.) (Omits schedules and exhibits. Southern Power agreed to provide supplementally the omitted schedules and exhibits to the SEC upon request.)
	(f)	8	-	Purchase and Sale Agreement by and between Progress Genco Ventures, LLC and Southern Power Company — Rowan LLC dated May 8, 2006. (Designated in Southern Power’s Form 10-Q for the quarter ended June 30, 2006, File No. 333-98553, as Exhibit 10(f)4.) (Omits schedules and exhibits. Southern Power agrees to provide supplementally the omitted schedules and exhibits to the SEC upon request.) (Southern Power requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Southern Power omitted such portions from the filing and filed them separately with the SEC.)
	(f)	9	-	Assignment and Assumption Agreement between Southern Power Company — Rowan LLC and Southern Power effective May 24, 2006. (Designated in Southern Power’s Form 10-Q for the quarter ended June 30, 2006, File No. 333-98553, as Exhibit 10(f)5.)

E-16

(14)	Code of Ethics
	Southern Company
	*	(a)	-	The Southern Company Code of Ethics.
	Alabama Power
		(b)	-	The Southern Company Code of Ethics. See Exhibit 14(a) herein.
	Georgia Power
		(c)	-	The Southern Company Code of Ethics. See Exhibit 14(a) herein.
	Gulf Power
		(d)	-	The Southern Company Code of Ethics. See Exhibit 14(a) herein.
	Mississippi Power
		(e)	-	The Southern Company Code of Ethics. See Exhibit 14(a) herein.
	Southern Power
		(f)	-	The Southern Company Code of Ethics. See Exhibit 14(a) herein.
(21)	Subsidiaries of Registrants
	Southern Company
	*	(a)	-	Subsidiaries of Registrant.
	Alabama Power
		(b)	-	Subsidiaries of Registrant. See Exhibit 21(a) herein.
	Georgia Power
		(c)	-	Subsidiaries of Registrant. See Exhibit 21(a) herein.
	Gulf Power
		(d)	-	Subsidiaries of Registrant. See Exhibit 21(a) herein.
	Mississippi Power
		(e)	-	Subsidiaries of Registrant. See Exhibit 21(a) herein.

E-17

	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.
	Mississippi Power
	*	(e)		1	-	Consent of Deloitte & Touche LLP.
	Southern Power
	*	(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.

E-18

	Southern Power
	*	(f)		-	Power of Attorney and resolution.
(31)	Section 302 Certifications
	Southern Company
	*	(a)	1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(a)	2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
	*	(b)	1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(b)	2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
	*	(c)	1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(c)	2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Gulf Power
	*	(d)	1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(d)	2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
	*	(e)	1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(e)	2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
	*	(f)	1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(f)	2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

E-19

(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.
	Southern Power
	*	(f)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
(101)	XBRL-Related Documents
	Southern Company
	*	INS	-	XBRL Instance Document
	*	SCH	-	XBRL Taxonomy Extension Schema Document
	*	CAL	-	XBRL Taxonomy Calculation Linkbase Document
	*	DEF	-	XBRL Definition Linkbase Document
	*	LAB	-	XBRL Taxonomy Label Linkbase Document
	*	PRE	-	XBRL Taxonomy Presentation Linkbase Document

E-20