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Notice of Annual Meeting of Stockholders — May 26, 2010

TIME AND DATE

10:00 a.m., ET, on Wednesday, May 26, 2010

PLACE

The Lodge Conference Center at Callaway Gardens
Highway 18
Pine Mountain, Georgia 31822

DIRECTIONS

From Atlanta, Georgia — take I-85 south to I-185 (Exit 21). From I-185 south, take Exit 34, Georgia Highway 18. Take Georgia Highway 18 east to Callaway.

From Birmingham, Alabama — take U.S. Highway 280 east to Opelika. Take I-85 north to Georgia Highway 18 (Exit 2). Take Georgia Highway 18 east to Callaway.

ITEMS OF BUSINESS

(1) Elect 11 members of the Board of Directors;

(2) Ratify appointment of independent registered public accounting firm;

(3) Consider and vote on an amendment to the By-Laws of the Company to adopt a majority vote standard;


(4)	Consider and vote on an amendment to the Company’s Certificate of Incorporation to eliminate cumulative voting in election of directors;
(5)	Consider and vote on an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of common stock;
(6)	and (7) Consider and vote on the stockholder proposals, if presented at the meeting, as described in Item Nos. 6 and 7 of the Proxy Statement; and
(8)	Transact other business properly coming before the meeting or any adjournments thereof.

RECORD DATE

Stockholders of record at the close of business on March 30, 2010 are entitled to attend and vote at the meeting.

ANNUAL REPORT TO STOCKHOLDERS

Appendix C to this Proxy Statement is Southern Company’s 2009 Annual Report.

By Order of the Board of Directors, G. Edison Holland, Jr., Corporate Secretary, April 13, 2010

Proxy Statement

Frequently Asked Questions


Q:		When will the Proxy Statement be mailed?

A:		The Proxy Statement will be mailed on or about April 13, 2010.

Q:		How do I give voting instructions?

A:		You may attend the meeting and give instructions in person or, as mentioned previously, give instructions by the Internet, by telephone, or by mail. Information for giving instructions is on the proxy form. The Proxies, named on the enclosed proxy form, will vote all properly executed proxies that are delivered pursuant to this solicitation and not subsequently revoked in accordance with the instructions given by you.

Q:		Why is my vote important?

A:		It is the right of every investor to vote on certain important matters that affect the Company. Further, for those investors whose shares are held by a broker, in 2009, the New York Stock Exchange and the Securities and Exchange Commission (SEC) each adopted rule changes. As a result of these rule changes, you must complete and return a voting instruction form to instruct the broker on how to vote in the election of Directors. Brokers can no longer vote uninstructed shares of their account holders in the election of Directors.

Q:		Can I change my vote?

A:		Yes, you may revoke your proxy by submitting a subsequent proxy or by written request received by the Company’s corporate secretary before the meeting.

Q:		Who can vote?

A:		All stockholders of record on the record date of March 30, 2010 may vote. On that date, there were 825,020,642 shares of Southern Company common stock (Common Stock) outstanding and entitled to vote.

Q:		How much does each share count?

A:		Each share counts as one vote, except votes for Directors may be cumulative. Abstentions that are marked on the proxy form are included for the purpose of determining a quorum, but shares that a broker fails to vote are not counted toward a quorum. Neither is counted for or against the matters being considered; however, abstentions and broker non-votes have the effect of a vote against Item Nos. 4 and 5.

Q:		What does it mean if I get more than one proxy form?

A:		You will receive a proxy form for each account that you have. Please vote proxies for all accounts to ensure that all your shares are voted. If you wish to consolidate multiple registered accounts, please contact Stockholder Services at (800) 554-7626.

Q:		Can the Company’s Proxy Statement be accessed from the Internet?

A:		Yes. You can access the Company’s website at www.southerncompany.com to view the 2010 Proxy Statement.

Q:		Does the Company offer electronic delivery of proxy materials?

A:		Yes. Most stockholders can elect to receive an e-mail that will provide an electronic link to the Proxy Statement, which includes the 2009 Annual Report as an appendix. Opting to receive your proxy materials on-line will save us the cost of producing and mailing documents and also will give you an electronic link to the proxy voting site.


		You may sign up for electronic delivery when you vote your proxy via the Internet or:

		n Go to our investor website at http://investor.southerncompany.com/;

		n Click on the words “Electronic Delivery of Proxy Materials”; and

		n Follow the directions provided to complete your enrollment.


		Once you enroll for electronic delivery, you will receive proxy materials electronically as long as your account remains active or until you cancel your enrollment. If you consent to electronic access, you will be responsible for your usual Internet-related charges (e.g., on-line fees and telephone charges) in connection with electronic viewing and printing of


		the Proxy Statement, which includes the 2009 Annual Report as an appendix. The Company will continue to distribute printed materials to stockholders who do not consent to access these materials electronically.

Q:		What is “householding?”

A:		Certain beneficial owners of the Common Stock sharing a single address may receive only one copy of the Proxy Statement, which includes the 2009 Annual Report as an appendix, unless the broker, bank, or nominee has received contrary instructions from any beneficial owner at that address. This practice — known as householding — is designed to reduce printing and mailing costs. If a beneficial owner would like to either participate or cancel participation in householding, he or she may contact Stockholder Services at (800) 554-7626 or at 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308 and ask to receive a Proxy Statement, which will be delivered promptly. As noted earlier, beneficial owners may view the Proxy Statement on the Internet.

Q:		When are stockholder proposals due for the 2011 Annual Meeting of Stockholders?

A:		The deadline for the receipt of stockholder proposals to be considered for inclusion in the Company’s proxy materials for the 2011 Annual Meeting of Stockholders is December 13, 2010. Proposals must be submitted in writing to Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. Additionally, the proxy solicited by the Board of Directors for next year’s meeting will confer discretionary authority to vote on any stockholder proposal presented at that meeting that is not included in the Company’s proxy materials unless the Company is provided written notice of such proposal no later than February 26, 2011.

Q:		Who pays the expense of soliciting proxies?

A:		These proxies are being solicited on behalf of the Company’s Board of Directors. The Company pays the cost of soliciting proxies. The officers or other employees of the Company or its subsidiaries may solicit proxies to have a larger representation at the meeting. The Company has retained Laurel Hill Advisory Group to assist with the solicitation of proxies for a fee not to exceed $10,000, plus reimbursement of out-of-pocket expenses.

The Company’s 2009 Annual Report to the SEC on Form 10-K will be provided without charge upon written request to Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.

Important notice regarding the availability of proxy materials for the Annual Meeting of Stockholders to be held on May 26, 2010:

This Proxy Statement, which includes the 2009 Annual Report as an appendix, is also available at http://investor.southerncompany.com/proxy.cfm.

Corporate Governance

COMPANY ORGANIZATION

Southern Company is a holding company managed by a core group of officers and governed by a Board of Directors that is currently comprised of 12 members.

At the 2010 Annual Meeting, stockholders will elect 11 Directors. The nominees for election as Directors consist of 10 non-employees and one executive officer of the Company.

The Board of Directors has adopted and operates under a set of Corporate Governance Guidelines which are available on the Company’s website at www.southerncompany.com under Investors/Corporate Governance.

CORPORATE GOVERNANCE WEBSITE

In addition to the Corporate Governance Guidelines (which include Board independence criteria), other information relating to corporate governance of the Company is available on the Company’s Corporate Governance webpage at www.southerncompany.com under Investors/Corporate Governance or directly at http://investor.southerncompany.com/governance.cfm, including:


n		Code of Ethics

n		Political Contributions Policy and Report

n		By-Laws of the Company

n		Executive Stock Ownership Guidelines

n		Board Committee Charters

n		Board of Directors — Background and Experience

n		Management Council — Background and Experience

n		SEC filings

n		Composition of Board Committees

n		Link for online communication with Board of Directors

The Corporate Governance documents also may be obtained by requesting a copy from Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.

DIRECTOR INDEPENDENCE

No Director will be deemed to be independent unless the Board of Directors affirmatively determines that the Director has no material relationship with the Company, directly, or as an officer, stockholder, or partner of an organization that has a relationship with the Company. The Board of Directors has adopted categorical guidelines which provide that a Director will not be deemed to be independent if within the preceding three years:


n		The Director was employed by the Company or the Director’s immediate family member was an executive officer of the Company.

n		The Director received, or the Director’s immediate family member received, during any 12-month period, direct compensation from the Company of more than $120,000, other than director and committee fees. (Compensation received by an immediate family member for services as a non-executive employee of the Company need not be considered.)

n		The Director was affiliated with or employed by, or the Director’s immediate family member was affiliated or employed in a professional capacity by, a present or former external auditor of the Company.


n		The Director was employed, or the Director’s immediate family member was employed, as an executive officer of a company where any member of the Company’s present executives serves on that company’s compensation committee.

n		The Director is a current employee, or the Director’s immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the Company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1,000,000 or two percent of that company’s consolidated gross revenues.

Additionally, a Director will be deemed not to be independent if the Director or the Director’s spouse serves as an executive officer of a charitable organization to which the Company made discretionary contributions exceeding the greater of $1,000,000 or two percent of the organization’s total annual charitable receipts.

In determining independence, the Board reviews and considers all commercial, consulting, legal, accounting, charitable, or other business relationships that a Director or the Director’s immediate family members have with the Company. This review specifically included all ordinary course transactions with entities with which the Directors are associated. In particular, the Board reviewed transactions between subsidiaries of the Company and The Home Depot, Inc. and Vulcan Materials Company as described under Certain Relationships and Related Transactions on page 64 of this Proxy Statement. Messrs. Francis S. Blake, a former Director, and Donald M. James are the Chief Executive Officers of The Home Depot, Inc. and Vulcan Materials Company, respectively. The Board determined that its subsidiaries followed the Company procurement policies and procedures, that the amounts were well under the thresholds contained in the Director independence requirements, and that neither Mr. Blake nor Mr. James had a direct or indirect material interest in the transactions.

Ms. Elizabeth Blake, the wife of Mr. Francis S. Blake, a former Director of the Company, is a Senior Vice President of Government Relations and Advocacy, and General Counsel for Habitat for Humanity International. In 2009, the Company, primarily through its foundation and the foundations of its subsidiaries, supported Habitat for Humanity International through charitable contributions of approximately $80,000. No other Director or immediate family member serves in an executive capacity for a charitable organization. The Board reviewed all contributions made by the Company and its subsidiaries to charitable organizations with which the Directors are associated. The Board determined that the contributions were consistent with similar contributions and none were approved outside the Company’s normal procedures.

As a result of its annual review of Director independence, the Board affirmatively determined that none of the following persons who are currently serving as Directors or are nominees for election as Directors has a material relationship with the Company and, as a result, such persons are determined to be independent: Juanita Powell Baranco, Jon A. Boscia, Thomas F. Chapman, Henry A. Clark III, H. William Habermeyer, Jr., Veronica M. Hagen, Warren A. Hood, Jr., Donald M. James, J. Neal Purcell, William G. Smith, Jr., Gerald J. St. Pé, and Larry D. Thompson. Also, Francis S. Blake, who served as a Director during 2009 until his resignation date of October 7, 2009, was determined not to have a material relationship with the Company and to be independent. David M. Ratcliffe, a current Director, is Chairman of the Board, President, and Chief Executive Officer of the Company and is not independent.

COMMUNICATING WITH THE BOARD

Communications may be sent to the Company’s Board or to specified Directors, including the Presiding Director, by regular mail or electronic mail. Regular mail should be sent to the attention of Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. The electronic mail address is CORPGOV@southerncompany.com. The electronic mail address also can be accessed from the Corporate Governance webpage located under “Investors” on the Southern Company website at www.southerncompany.com, under the link entitled “Governance Inquiries.” With the exception of commercial solicitations, all stockholder communications directed to the Board or to specified Directors will be relayed to them.

DIRECTOR COMPENSATION

Only non-employee Directors are compensated for Board service.


		Annual retainers:

n		$85,000 cash retainer

n		$12,500 if serving as a chair of a committee of the Board

n		$12,500 if serving as the Presiding Director of the Board

		Annual equity grant:

n		$90,000 in deferred Common Stock units until Board membership ends

		Meeting fees:

n		Meeting fees are not paid for participation in the initial eight meetings of the Board in a calendar year. If more than eight meetings of the Board are held in a calendar year, $2,500 will be paid for participation in each meeting of the Board beginning with the ninth meeting.

n		Meeting fees are not paid for participation in a meeting of a committee of the Board.

DIRECTOR DEFERRED COMPENSATION PLAN

The $90,000 equity grant is required to be deferred in shares of Common Stock under the Deferred Compensation Plan for Directors of The Southern Company (Director Deferred Compensation Plan) and 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 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. Such 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; or

•	at the prime interest rate, 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. The Company has established a grantor trust that primarily holds Common Stock that funds the Common Stock units that are distributed in Common Stock. Directors have voting rights in the shares held in the trust attributable to these units.

DIRECTOR COMPENSATION TABLE

The following table reports all compensation to the Company’s non-employee Directors during 2009, including amounts deferred in the Director Deferred Compensation Plan. Non-employee Directors do not receive Option Awards or Non-Equity Incentive Plan Compensation, and there is no pension plan for non-employee Directors.


									Change in
									Pension Value
	Fees								and
	Earned						Non-Equity		Nonqualified
	or Paid		Stock		Option		Incentive Plan		Deferred		All Other
	in Cash		Awards		Awards		Compensation		Compensation		Compensation
Name	($)(1)		($)(2)		($)		($)		Earnings ($)		($)(3)		Total ($)


Juanita Powell Baranco		97,500		90,000		—		—		—		1,693		189,193

Francis S. Blake(4)		70,834		75,000		—		—		—		—		145,834

Jon A. Boscia		85,000		90,000		—		—		—		—		175,000

Thomas F. Chapman		97,500		90,000		—		—		—		—		187,500

Henry A. Clark III(5)		21,250		22,500		—		—		—		—		43,750

H. William Habermeyer, Jr.		97,500		90,000		—		—		—		—		187,500

Veronica M. Hagen		99,584		90,000		—		—		—		—		189,584

Warren A. Hood, Jr.		85,000		90,000		—		—		—		—		175,000

Donald M. James		97,500		90,000		—		—		—		—		187,500

J. Neal Purcell		97,500		90,000		—		—		—		—		187,500

William G. Smith, Jr.		97,500		90,000		—		—		—		835		188,335

Gerald J. St. Pé		85,000		90,000		—		—		—		—		175,000


(1)		Includes amounts voluntarily deferred in the Director Deferred Compensation Plan.
(2)		Represents deferred Common Stock units.
(3)		Consists of tax “gross-ups” for taxes associated with spousal air travel.
(4)		Mr. Blake resigned as a Director of the Company on October 7, 2009.
(5)		Mr. Clark became a Director of the Company on October 19, 2009.

DIRECTOR STOCK OWNERSHIP GUIDELINES

Under the Company’s Corporate Governance Guidelines, non-employee Directors are required to beneficially own, within five years of their initial election to the Board, Common Stock equal to at least four times the annual Director retainer fee.

BOARD LEADERSHIP STRUCTURE

The Board believes that the combined role of Chief Executive Officer and Chairman is most suitable for the Company because Mr. Ratcliffe is the Director most familiar with the Company’s business and industry, including the regulatory structure and other industry-specific matters, as well as being most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Independent Directors and management have different perspectives and roles in strategy development. The Chief Executive Officer brings company-specific experience and expertise, while the Company’s independent Directors bring experience, oversight, and expertise from outside the Company and its industry. The Board believes that the combined role of Chief Executive Officer and Chairman promotes the development and execution of the Company’s strategy and facilitates the flow of information between management and the Board, which is essential to effective corporate governance.

The Board believes the combined role of Chief Executive Officer and Chairman, together with an independent Presiding Director having the duties described below, is in the best interest of stockholders because it provides the appropriate balance between independent oversight of management and the development of strategy.

PRESIDING DIRECTOR

Mr. Chapman served as the Presiding Director from January 1, 2008 until December 31, 2009. Mr. James was appointed to serve as the Presiding Director effective January 1, 2010 until December 31, 2011. The Presiding Director is selected bi-annually by and from the independent Directors. Non-management Directors meet, without management, at least quarterly, and at other times as deemed appropriate by the Presiding Director or two or more other independent Directors. As the Presiding Director, Mr. James is responsible for chairing executive sessions and acting as the principal liaison between the Chairman and the non-management Directors. However, each Director is afforded direct and complete access to the Chairman at any time as such Director deems necessary or appropriate. The Presiding Director meets regularly with the Chairman and also serves as the contact Director for stockholders. The Presiding Director will also be involved in communicating any sensitive issues to the Directors. The Presiding Director also chairs Board meetings in the absence of the Chairman.

MEETINGS OF NON-MANAGEMENT DIRECTORS

Non-management Directors meet in executive session with no member of management present on each regularly-scheduled Board meeting date. The Presiding Director chairs each of these executive sessions.

COMMITTEES OF THE BOARD


		Committee Charters

Charters for each of the five standing committees can be found at the Company’s website — www.southerncompany.com under Investors/Corporate Governance.


		Audit Committee:

n		Members are Mr. Smith (Chair), Mr. Boscia (1), and Mr. Hood

n		Met 10 times in 2009

n		Oversees the Company’s financial reporting, audit processes, internal controls, and legal, regulatory, and ethical compliance; appoints the Company’s independent registered public accounting firm, approves its services and fees, and establishes and reviews the scope and timing of its audits; reviews and discusses the Company’s financial statements with management and the independent registered public accounting firm, including critical accounting policies and practices, material alternative financial treatments within generally accepted accounting principles, proposed adjustments, control recommendations, significant management judgments and accounting estimates, new accounting policies, changes in accounting principles, any disagreements with management, and other material written communications between the internal auditors and/or the independent registered public accounting firm and management; and recommends the filing of the Company’s annual financial statements with the SEC.

The Board has determined that the members of the Audit Committee are independent as defined by the New York Stock Exchange corporate governance rules within its listing standards and rules of the SEC promulgated pursuant to the Sarbanes-Oxley Act of 2002. The Board has determined that Mr. Smith qualifies as an “audit committee financial expert” as defined by the SEC.

(1) Mr. Blake resigned from the Board effective October 7, 2009 and Mr. Boscia was appointed a member of the Audit Committee effective October 19, 2009.

The Compensation Committee does not believe that its consultant’s independence was affected by the additional services provided by the firm. However, beginning in 2010, all such services must be approved in advance by the Chair of the Compensation Committee, as provided in the Compensation Committee’s Charter as amended effective February 15, 2010.


		Compensation Committee Interlocks and Insider Participation

None of the persons who served as members of the Compensation Committee during 2009 was an officer or employee of the Company during 2009, or at any time in the past, nor had reportable transactions with the Company.


		Finance Committee:

n		Members are Mr. Clark (Chair) (1), Mr. James (2), and Mr. Purcell

n		Met seven times in 2009

n		Reviews the Company’s financial matters, recommends actions such as dividend philosophy to the Board, and approves certain capital expenditures.

The Board has determined that each member of the Finance Committee is independent.

(1) Mr. Clark was appointed a member of the Finance Committee on October 19, 2009 and Chair of the Finance Committee effective January 1, 2010. Mr. Boscia served as a member of the Finance Committee until October 19, 2009.

(2) Mr. James, previously the Chair of the Finance Committee, was appointed Presiding Director effective January 1, 2010.


		Governance Committee:

n		Members are Ms. Baranco (Chair), Mr. Chapman, Ms. Hagen (1), and Mr. St. Pé

n		Met seven times in 2009

n		Oversees the composition of the Board and its committees, determines non-management Directors’ compensation, maintains the Company’s Corporate Governance Guidelines, and coordinates the performance evaluations of the Board and its committees.

The Board has determined that each member of the Governance Committee is independent.

(1) Ms. Hagen was appointed a member of the Governance Committee effective February 16, 2009.


		Nominees for Election to the Board

The Governance Committee, comprised entirely of independent Directors, is responsible for identifying, evaluating, and recommending nominees for election to the Board. The Governance Committee solicits recommendations for candidates for consideration from its current Directors and is authorized to engage third-party advisers to assist in the identification and evaluation of candidates for consideration. Any stockholder may make recommendations to the Governance Committee by sending a written statement setting forth the candidate’s qualifications, relevant biographical information, and signed consent to serve. These materials should be submitted in writing to the Company’s Assistant Corporate Secretary and received by that office by December 13, 2010 for consideration by the Governance Committee as a nominee for election at the Annual Meeting of Stockholders to be held in 2011. Any stockholder recommendation is reviewed in the same manner as candidates identified by the Governance Committee or recommended to the Governance Committee.

While the Company’s Corporate Governance Guidelines do not prescribe diversity standards, such Guidelines mandate that the Board as a whole should be diverse. At least annually, the Governance Committee evaluates the expertise and needs of the Board to determine the proper membership and size. As part of this evaluation, the Governance Committee would consider aspects of diversity, such as diversity of age, race, gender, education, industry, and public and private service in the selection of candidates to serve on the Board. The Governance Committee only considers candidates with the highest degree of integrity and ethical standards. The Governance Committee evaluates a candidate’s independence from management, ability to provide sound and informed judgment, history of achievement reflecting superior standards, willingness to commit sufficient time, financial literacy, and number of other board memberships. The Board as a whole should also have collective

knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and the Company’s industry. During 2009, the Governance Committee engaged the services of a third-party search firm to aid in identifying prospective candidates and evaluating their qualifications. The Governance Committee recommends candidates to the Board for consideration as nominees. Final selection of the nominees is within the sole discretion of the Board.

Mr. Henry A. Clark III was recommended by the Governance Committee for election to the Board and was elected as a Director effective October 19, 2009. Mr. Clark was identified jointly by management and the members of the Governance Committee.

Mr. Larry D. Thompson was recommended by the Governance Committee for nomination for election to the Board and was selected as a nominee for election as a Director. Mr. Thompson was identified jointly by the members of the Governance Committee and the third-party search firm referenced above.


		Nuclear/Operations Committee:

n		Members are Mr. Habermeyer (Chair), Ms. Baranco, Ms. Hagen (1), and Mr. St. Pé

n		Met five times in 2009

n		Oversees significant information, activities, and events relative to significant operations of the Company including nuclear and other generation facilities, transmission and distribution, fuel, and information technology initiatives.

(1) Ms. Hagen was appointed to the Nuclear/Operations Committee effective February 16, 2009.

BOARD RISK OVERSIGHT

The Board and its committees have both general and specific risk oversight responsibilities. The Board has broad responsibility to provide oversight of significant risks to the Company primarily through direct engagement with Company management and through delegation of ongoing risk oversight responsibilities to the committees. The charters of the committees as approved by the Board designate the areas of risk for which each committee is responsible for providing ongoing oversight. Each committee provides oversight of the significant risks as described in its charter. The committees report to the Board on their oversight activities and elevate review of risk issues to the Board as appropriate. For each committee, the Chief Executive Officer of the Company has designated a member of management as the primary responsible officer for providing information and updates related to the significant risks. These officers ensure that all significant risks identified on the Company’s risk profile are reviewed with the Board and/or the appropriate committee(s) at least annually. In addition to oversight of its designated risks, the Audit Committee also is responsible for reviewing the adequacy of the risk oversight process and for reviewing documentation demonstrating that appropriate risk management and oversight are occurring. In order to fulfill this duty, a report is made to the Audit Committee at least annually. This report documents which significant risk reviews have occurred and the committee(s) reviewing such risks. In addition, an overview is provided at least annually of the risk assessment and profile process conducted by Company management. Annually, the Board and the Audit Committee review the Company’s risk profile to ensure that oversight of each risk is properly designated to an appropriate committee or the full Board. The Audit Committee receives regular updates from Internal Auditing, as needed, and quarterly updates as part of the disclosure controls process.

DIRECTOR ATTENDANCE

The Board met seven times in 2009. The average attendance for Directors at all Board and committee meetings was 95 percent. No nominee attended less than 75 percent of applicable meetings.

Directors are expected to attend the Annual Meeting of Stockholders. With the exception of Mr. Francis S. Blake, a former Director, all the members of the Board of Directors serving on May 27, 2009, the date of the 2009 Annual Meeting of Stockholders, attended the meeting.

Stock Ownership Table

STOCK OWNERSHIP OF DIRECTORS, NOMINEES, AND EXECUTIVE OFFICERS

The following table shows the number of shares of Common Stock owned by Directors, nominees, and executive officers as of December 31, 2009. The shares owned by all Directors, nominees, and executive officers as a group constitute less than one percent of the total number of shares of the class outstanding.


			Shares Beneficially Owned Include:
					Shares
					Individuals
	Shares				Have Rights to
	Beneficially		Deferred Stock		Acquire within		Shares Held by
Directors, Nominees, and Executive Officers	Owned(1)		Units(2)		60 days(3)		Family Members(4)

Juanita Powell Baranco		22,494		21,970

Jon A. Boscia		9,736		5,736

W. Paul Bowers		357,192				346,482

Thomas F. Chapman		41,958		41,958

Henry A. Clark III(5)		722		722

Thomas A. Fanning		434,751				427,157

Michael D. Garrett		423,193				421,059

H. William Habermeyer, Jr.		7,383		7,383

Veronica M. Hagen		6,185		6,185

Warren A. Hood, Jr.		15,271		14,748

Donald M. James		57,101		55,101

Charles D. McCrary		511,472				505,903

J. Neal Purcell		46,488		36,264				224

David M. Ratcliffe		2,873,398				2,854,768

William G. Smith, Jr.		25,625		21,594

Gerald J. St. Pé		108,506		54,041				9,342

Larry D. Thompson(6)		0		0		0		0

Directors, Nominees, and Executive Officers as a Group (23 people)		6,278,843		265,702		5,849,568		9,566


(1)	“Beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, 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.

(4)		Each Director disclaims any interest in shares held by family members. Shares indicated are included in the Shares Beneficially Owned column.

(5)		Mr. Clark was elected as a Director of the Company on October 19, 2009.

(6)		Mr. Thompson is a nominee for Director.

Matters to be Voted Upon

ITEM NO. 1 — ELECTION OF DIRECTORS

Nominees for Election as Directors

The Proxies named on the proxy form will vote, unless otherwise instructed, each properly executed proxy form for the election of the following nominees as Directors. If any named nominee becomes unavailable for election, the Board may substitute another nominee. In that event, the proxy would be voted for the substitute nominee unless instructed otherwise on the proxy form. Each nominee, if elected, will serve until the 2011 Annual Meeting of Stockholders.

The Board of Directors, acting upon the recommendation of the Governance Committee, nominates the following individuals for election to the Southern Company Board of Directors. Each nominee holds or has held senior executive positions, maintains the highest degree of integrity and ethical standards, and complements the needs of the Company. Through their positions, responsibilities, skills, and perspectives, which span various industries and organizations, these nominees represent a Board that is diverse and possessing the collective knowledge and experience in accounting, finance, leadership, business operations, risk management, and corporate governance as detailed below. The Governance Committee evaluated each nominee’s independence from management, ability to provide sound and informed judgment, history of achievement reflecting superior standards, willingness to commit sufficient time, financial literacy, community involvement, and the number of other board memberships.



		Juanita Powell Baranco Age: Director since: Board committees: Principal occupation: Director qualifications: Other directorships:		61 2006 Governance (Chair), Nuclear/Operations Executive Vice President and Chief Operating Officer of Baranco Automotive Group, automobile sales Ms. Baranco had a successful law career, which included serving as Assistant Attorney General for the State of Georgia, before she and her husband founded the first Baranco dealership in Atlanta in 1978. She served as a member of the board at Georgia Power, the largest subsidiary of the Company, from 1997-2006. During her tenure on the Georgia Power Board, she was a member of the Controls and Compliance, Diversity, Executive, and Nuclear Operations Overview Committees. She served on the Federal Reserve Bank of Atlanta board for a number of years and also on the John H. Harland Company Board of Directors. An active leader in the Atlanta community, Ms. Baranco has served as a Director of Cox Radio, Inc. She serves as Chair of the Board of Trustees for Clark Atlanta University and Board Chair for the Sickle Cell Foundation of Georgia. She is also past Chair of the Board of Regents for the University System of Georgia. The Board has benefitted from Ms. Baranco’s particular expertise in business operations and her civic involvement. None (formerly a Director of Georgia Power and Cox Radio, Inc.)



		J. Neal Purcell Age: Director since: Board committees: Director qualifications: Other directorships:		68 2003 Compensation and Management Succession (Chair), Finance Mr. Purcell is a retired Vice-Chairman of KPMG. From October 1998 until his retirement in 2002, Mr. Purcell was in charge of National Audit Practice Operations. Over the course of his career at KPMG, he was a member of its Board of Directors and its Management Committee. He performed numerous peer review audits and quality of audits reviews during his career. Mr. Purcell is currently a Director of Kaiser Permanente Health Care and Hospitals and Synovus Financial Corp. where he is serves as the Chair of each Audit Committee. He also serves on the Board of Trustees of Emory University where he is Chair of the Compensation Committee and on the Board of Directors of Emory Healthcare System. His financial and accounting expertise, his knowledge of the communities served by Southern Company’s affiliates, and his personal involvement in those communities are valuable to the Board. During his time on the Board, Mr. Purcell has also chaired the Audit Committee and served as the Company’s first audit committee financial expert. Kaiser Permanente Health Care and Hospitals, Synovus Financial Corp. (formerly a Director of Dollar General Corporation)


		David M. Ratcliffe Age: Director since: Principal occupation: Director qualifications: Other directorships:		61 2003 Chairman of the Board, President, and Chief Executive Officer of the Company As Southern Company’s Chairman of the Board, Chief Executive Officer, and President, Mr. Ratcliffe is uniquely qualified to serve on the Board. As an employee with more than 39 years of service, Mr. Ratcliffe understands the electric utility business, the regulatory structure, and other industry-specific matters that affect Southern Company. He is also a Director of CSX Corporation where he currently serves on the Executive, and Operations and Public Affairs Committees and as Chair of the Finance Committee. CSX Corporation, Alabama Power, Georgia Power, and Southern Power



		Larry D. Thompson Age: Director since: Board committee: Principal occupation: Director qualifications: Other directorship:		64 Nominee Not applicable Senior Vice President - Government Affairs, General Counsel, and Secretary of PepsiCo, Inc., food and beverage PepsiCo ranks among the world’s largest convenient food and beverage companies. In his current role at PepsiCo, Mr. Thompson is responsible for PepsiCo’s worldwide legal function, as well as its government affairs organization and the company’s charitable foundation. Prior to joining PepsiCo in 2004, Mr. Thompson served as a Senior Fellow with The Brookings Institution. His government career also includes serving in the United States Department of Justice and leading the National Security Coordination Council. In 2002, President George W. Bush named Mr. Thompson to head the Corporate Fraud Task Force. Mr. Thompson is a director or trustee of various investment companies in the Franklin Templeton group of mutual funds and has recently been elected to the board of Cbeyond, Inc. Mr. Thompson’ s corporate governance and legal expertise will be valuable to the Board. Cbeyond, Inc.

Each nominee has served in his or her present position for at least the past five years, unless otherwise noted.

The affirmative vote of a plurality of shares present and entitled to vote is required for the election of Directors. Stockholders are entitled to cumulative voting in the election of Directors. See Item No. 3 below for a discussion of cumulative voting.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” THE NOMINEES LISTED IN ITEM NO. 1.

ITEM NO. 2 — RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Audit Committee of the Board of Directors has appointed Deloitte & Touche LLP (Deloitte & Touche) as the Company’s independent registered public accounting firm for 2010. This appointment is being submitted to stockholders for ratification. Representatives of Deloitte & Touche will be present at the Annual Meeting to respond to appropriate questions from stockholders and will have the opportunity to make a statement if they desire to do so.

The affirmative vote of a majority of shares present and entitled to vote is required for ratification of the appointment of the independent registered public accounting firm.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEM NO. 2.

ITEM NO. 3 — TO AMEND THE COMPANY’S BY-LAWS TO (1) IMPLEMENT A MAJORITY VOTE STANDARD FOR THE ELECTION OF DIRECTORS IN UNCONTESTED ELECTIONS, RETAINING A PLURALITY VOTE STANDARD IN CONTESTED ELECTIONS, AND (2) ELIMINATE CUMULATIVE VOTING IN UNCONTESTED ELECTIONS, EACH CONDITIONED ON THE ELIMINATION OF CUMULATIVE VOTING IN THE CERTIFICATE OF INCORPORATION

The Company’s Board of Directors determined that it would be in the best interest of the Company and its stockholders to allow for majority voting and to eliminate cumulative voting in uncontested elections of Directors. The Board recommends that the stockholders approve an amendment to the By-Laws to change the standard for the election of Directors in uncontested elections from a plurality voting standard to a majority voting standard and also to eliminate cumulative voting in uncontested elections, subject to the elimination of cumulative voting in the Certificate of Incorporation, as described more fully in Item No. 4 below.

Under the current plurality vote standard, a nominee for Director in an election can be elected or re-elected with as little as a single affirmative vote, even while a substantial majority of the votes cast are “withheld” from that nominee. The proposed majority vote standard would require that a nominee for Director in an uncontested election receive a “for” vote from a majority of the votes present and voting at a stockholders’ meeting to be elected to the Board. Additionally, the By-Laws currently provide that when electing Directors, stockholders may exercise cumulative voting rights. Under cumulative voting, in voting for Directors each holder of Common Stock is entitled to cast a number of votes equal to the number of votes he or she would be entitled to cast with respect to his or her shares of Common Stock multiplied by the number of Directors to be elected. A stockholder may give one candidate all the votes such stockholder is entitled to cast or may distribute such votes among as many candidates as such stockholder chooses. The Board feels that cumulative voting and a majority vote standard are incompatible, and is recommending the elimination of cumulative voting in uncontested elections in conjunction with the adoption of a majority vote standard.

The Board is seeking to eliminate cumulative voting and to implement a majority vote standard in uncontested elections because it believes that such changes are in the best interest of stockholders at this time. The Board recommends retaining cumulative voting in the By-Laws for any contested election of Directors, to which a plurality standard would apply. Please see Item No. 4 below for additional information regarding the proposed elimination of cumulative voting as contained in the Certificate of Incorporation.


		Background of This Item

The proposed majority vote standard would require that a nominee for Director in an uncontested election receive a majority of the votes cast at a stockholder meeting in order to be elected to the Board. The Board believes that the proposed majority vote standard for uncontested elections is a more equitable standard. At present, a plurality vote standard guarantees the election of a Director in an uncontested election; however, a majority vote standard would mean that nominees in uncontested elections are only elected if a majority of the votes cast are voted in their favor. The Board believes that this majority vote standard in uncontested Director elections will strengthen the Director nomination process and enhance Director accountability.

Additionally, the Board will add appropriate provisions to its Corporate Governance Guidelines to require any nominee for election as a Director of the Company to submit an irrevocable letter of resignation as a condition to being named as such nominee, which would be tendered in the event that nominee fails to receive the affirmative vote of a majority of the votes cast in an uncontested election at a meeting of stockholders. Such resignation would be considered by the Board, and the Board would be required to either accept or reject such resignation within 90 days from the certification of the election results.

The By-Laws also currently provide for cumulative voting in the election of Directors. The proposed amendment would eliminate cumulative voting in uncontested elections of Directors, but retain cumulative voting in contested elections of Directors.

The Board does not believe that it should amend the By-Laws to establish a majority vote standard and to eliminate cumulative voting while the Company’s Certificate of Incorporation still provides for cumulative voting. The elimination of cumulative voting is desirable in connection with the adoption of the majority vote standard with respect to uncontested elections. Because both the Certificate of Incorporation and the By-Laws currently provide for cumulative voting, the Board

recommends that the provisions in the Certificate of Incorporation relating to cumulative voting be eliminated. The Board believes that less confusion will result if both the majority vote standard and cumulative voting provisions are contained only in the By-Laws rather than in both the By-Laws and the Certificate of Incorporation. This proposed amendment does not provide any less protection to stockholders because under the Company’s By-Laws, stockholders are required to ratify any amendment to the By-Laws, and any further change in either the majority vote standard or cumulative voting would be subject to the stockholder ratification requirement.


		Amendment

The proposed By-Law amendment would include the following:


•	The By-Laws will be amended to remove provisions about cumulative voting for Directors in uncontested elections and

•	The plurality voting provisions in the By-Laws will be replaced with provisions requiring that, in order to be elected in an uncontested election, a nominee for Director must receive the affirmative vote of a majority of the votes cast at a meeting of stockholders; provided that, in contested elections, the affirmative vote of a plurality of the votes cast will be required to elect a Director.

A complete text of the amendment is set forth in Appendix A.

The affirmative vote of a majority of shares present and entitled to vote is required for amendment of the By-Laws as presented in this Item No. 3.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEM NO. 3.

ADOPTION OF THIS ITEM NO. 3 IS CONDITIONED ON THE APPROVAL BY STOCKHOLDERS OF ITEM NO. 4 BELOW. NEITHER ITEM NO. 3 NOR ITEM NO. 4 WILL BE IMPLEMENTED UNLESS BOTH ITEMS ARE APPROVED.

ITEM NO. 4 — TO AMEND THE CERTIFICATE OF INCORPORATION TO ELIMINATE CUMULATIVE VOTING IN ELECTIONS OF DIRECTORS, CONDITIONED UPON ADOPTION OF THE MAJORITY VOTE STANDARD AND THE ELIMINATION OF CUMULATIVE VOTING IN UNCONTESTED ELECTIONS IN THE BY-LAWS

The Board has determined that it would be in the best interest of the Company and its stockholders to require that a nominee for Director in an uncontested election receive a majority of the votes cast at a stockholders’ meeting to be elected to the Board (see Item No. 3 above). The Board is seeking to eliminate cumulative voting in uncontested elections because it believes that a change to a majority vote standard in uncontested elections is in the best interest of stockholders at this time, and it views cumulative voting as inconsistent with a majority vote standard for the election of Directors.

The elimination of cumulative voting in uncontested elections requires an amendment to the By-Laws as discussed in Item No. 3 above and also requires an amendment to the Certificate of Incorporation, which would remove subdivision (2) of ARTICLE NINTH (the cumulative voting provision). The Board feels it is appropriate to remove cumulative voting entirely from the Certificate of Incorporation and to amend the cumulative voting provisions discussed above in the By-Laws so that all of the provisions pertaining to voting in Director elections are contained in the By-Laws. As discussed above, cumulative voting will be permitted in a contested election, to which the plurality voting standard applies.

This amendment to the Certificate of Incorporation has been approved and declared advisable by the Board but requires adoption by the Company’s stockholders. This elimination would facilitate adoption of the majority vote standard for the election of Directors in the manner described above in Item No. 3.

This item would not change the present number of Directors, and the Board would retain the authority to change that number and to fill any vacancies or newly created directorships.


		Background of This Item

The Board is seeking to eliminate cumulative voting because it believes that a change to a majority vote standard in uncontested elections would be in the best interest of stockholders at this time and it views cumulative voting as incompatible with a majority vote standard for election.


		Amendment

The proposed amendment would eliminate subdivision (2) of ARTICLE NINTH of the Certificate of Incorporation in its entirety.

Approval of this Item requires the affirmative vote of at least two-thirds of the outstanding shares of the Company’s Common Stock.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEM NO. 4.

ADOPTION OF THIS ITEM NO. 4 IS CONDITIONED ON THE APPROVAL BY STOCKHOLDERS OF ITEM NO. 3 ABOVE. NEITHER ITEM NO. 3 NOR ITEM NO. 4 WILL BE IMPLEMENTED UNLESS BOTH ITEMS ARE APPROVED.

ITEM NO. 5 — TO AMEND THE COMPANY’S CERTIFICATE OF INCORPORATION TO INCREASE THE NUMBER OF AUTHORIZED SHARES OF COMMON STOCK

The Board has proposed and declared advisable, and is recommending to the stockholders, approval of an amendment to the Certificate of Incorporation of the Company to increase the total number of shares of Common Stock, par value $5 per share, that the Company has authority to issue, from 1,000,000,000 to 1,500,000,000.

Of the 1,000,000,000 shares that the Company presently is authorized to issue, there were 825,020,642 shares outstanding as of March 30, 2010. In addition, on March 30, 2010, approximately 84,661,139 shares were reserved for issuance under the Southern Investment Plan (a dividend reinvestment and direct purchase plan) and the Company’s employee and director stock plans. The proposed increase in the amount of authorized but unissued Common Stock is considered necessary to provide the Company with the flexibility in the future to issue shares of Common Stock for future financing transactions, acquisitions, stock dividends or distributions, stock splits, issuances under the Southern Investment Plan and employee and director stock plans, and other general corporate purposes. The additional shares of Common Stock that will be available for issuance will be identical in terms to the shares of Common Stock currently authorized under the Certificate of Incorporation of the Company.

If the proposed amendment is adopted, the Company would be permitted to issue the authorized shares without further stockholder approval, except to the extent otherwise required by law, by a securities exchange on which the Common Stock is listed at the time, or by the Certificate of Incorporation. The New York Stock Exchange, on which the Common Stock is now listed, currently requires stockholder approval as a prerequisite to listing shares in certain instances, including acquisition transactions where the issuance could increase the number of outstanding shares by 20% or more.

The additional shares of Common Stock that will be available for issuance will be identical in terms to the shares of Common Stock currently authorized under the Certificate of Incorporation of the Company. Stockholders do not have preemptive rights to subscribe for or purchase additional shares of the Common Stock.

The Company has no current plans, agreements, or arrangements for the issuance of additional Common Stock other than pursuant to the Southern Investment Plan, the Company’s employee and director stock plans, and the Company’s continuous equity offering program. However, the additional authorized shares would be available for issuance (subject to further stockholder approval only as noted above) at such times and for such other corporate purposes as the Board may approve, including possible future financing transactions, acquisitions, stock dividends or distributions, and stock splits and other general corporate purposes.

Depending upon the nature and terms thereof, additional issuances of the Common Stock could enable the Board to render more difficult or discourage an attempt to obtain control of the Company. For example, the issuance of shares of Common Stock in a public or private sale, merger, or similar transaction would increase the number of the Company’s outstanding shares, thereby diluting the interest of a party seeking to take over the Company. If Item No. 5 is adopted, more Common

Stock of the Company would be available for such purposes than is currently available. The proposed increase in the number of authorized shares of Common Stock is not in response to any effort by any person or group to obtain control of the Company.

Issuances of additional shares of Common Stock, depending upon their timing and circumstances, also may dilute earnings per share and decrease the book value per share of shares already outstanding.

The vote needed to pass this proposed amendment of the Certificate of Incorporation is a majority of the shares of the Company’s stock outstanding and entitled to vote. If approved by stockholders, ARTICLE FOURTH of the Certificate of Incorporation will be amended to read as follows:

“The total number of shares of stock which the corporation shall have authority to issue is 1,500,000,000 shares, all of which are to be shares of common stock with a par value of five dollars ($5) each.”

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEM NO. 5.

ITEM NO. 6 — STOCKHOLDER PROPOSAL ON CLIMATE CHANGE ENVIRONMENTAL REPORT

The Company has been advised that The Sisters of Charity of Saint Elizabeth, P. O. Box 476, Convent Station, New Jersey 07961-0476, holder of 100 shares of Common Stock; American Baptist Home Mission Societies, P. O. Box 851, Valley Forge, Pennsylvania 19482-0851, holder of 1,742 shares of Common Stock; Benedictine Sisters Charitable Trust, 285 Oblate Drive, San Antonio, Texas 78216, holder of 100 shares of Common Stock; Benedictine Sisters of Virginia, Saint Benedict Monastery, 9535 Linton Hall Road, Bristow, Virginia 20136-1217, holder of 2,000 shares of Common Stock; Board of Pensions of the Evangelical Lutheran Church in America, 800 Marquette Avenue, Suite 1050, Minneapolis, Minnesota 55402-2892, holder of 12,871 shares of Common Stock; Calvert Asset Management Company, Inc., 4550 Montgomery Avenue, Bethesda, Maryland 20814, representing four shareholders — Calvert Large Cap Value Fund, holder of 64,400 shares of Common Stock, Summit Zenith Portfolio, holder of 137,800 shares of Common Stock, Summit Balanced Index Portfolio, holder of 719 shares of Common Stock, and Summit S&P 500 Index Portfolio, holder of 19,204 shares of Common Stock; Catholic Health East, 3805 West Chester Pike, Suite 100, Newtown Square, Pennsylvania 19073-2304, holder of 150 shares of Common Stock; Catholic Healthcare Partners, 615 Elsinore Place, Cincinnati, Ohio 45202, holder of 2,000 shares of Common Stock; Connecticut Retirement Plans and Trust Funds, 55 Elm Street, Hartford, Connecticut 06106-1773, holder of 169,619 shares of Common Stock; Providence Trust, 515 SW 24th Street, San Antonio, Texas 78207-4619, holder of 5,700 shares of Common Stock; and Sisters of St. Dominic of Caldwell New Jersey, 40 South Fullerton Avenue, Montclair, New Jersey 07042, holder of 100 shares of Common Stock, propose to submit the following resolution at the 2010 Annual Meeting of Stockholders.

“Whereas: The International Energy Agency (IEA) warned in its 2007 World Energy Outlook that ‘urgent action is needed if greenhouse gas [GHG] concentrations are to be stabilized at a level that would prevent dangerous interference with the climate system.’ In its 2009 report the IEA notes that ‘The scale and breadth of the energy challenge is enormous — far greater than many people realise. But it can and must be met. The recession, by curbing the growth in greenhouse-gas emissions, has made the task of transforming the energy sector easier by giving us an unprecedented, yet relatively narrow, window of opportunity to take action to concentrate investment on low-carbon technology.’

“In October 2006, a report authored by former chief economist of The World Bank, Sir Nicolas Stern, estimated that climate change will cost between 5% and 20% of GDP if emissions are not reduced, and that GHGs can be reduced at a cost of approximately 1% of global economic growth.

“U.S. power plants are responsible for nearly 40% of the country’s carbon dioxide emissions, and 10% of global carbon dioxide emissions.

“Coal-burning power plants are responsible for 80% of carbon dioxide emissions from all U.S. power plants and Southern Co. is the second-largest emitter of CO₂, the principal GHG linked to climate change, among U.S. power generators.

“Levels of carbon dioxide, which persists in the atmosphere for over 100 years, are now higher than anytime in the past 400,000 years and they will continue to rise as long as emissions from human activities continue.

“President Obama and many members of Congress are pressing on plans to limit greenhouse gas emissions; this will surely impact the business of our Company regardless of the mechanisms.

“AEP, the nation’s largest carbon dioxide emitter, Entergy and Exelon have set total GHG emissions reduction targets. Duke, Exelon, FPL, NRG, and others, through their participation in the U.S. Climate Action Partnership, have publicly stated that the U.S. should reduce its GHG footprint by 60% to 80% from current levels by 2050. They have endorsed adoption of mandatory federal policy to limit CO₂ emissions to provide economic and regulatory certainty needed for major investments in our energy future.

“Southern opposes mandatory regulation of CO₂ and other GHG emissions in favor of voluntary action. While our company has added cleaner natural gas capacity, is investing in renewable energy, has reduced the intensity of its CO₂ emissions, and looks to reduce GHG emissions by 80% by 2050 (Southern Company response to CDP6), we believe Southern still needs to articulate a cohesive business plan for dealing with climate risk and opportunity, and offer robust responses to the financial, regulatory, and technology impacts of the climate crisis.

“RESOLVED: Shareholders request that the Board of Directors report to shareholders actions the company would need to take to reduce total CO₂ emissions, including quantitative goals for existing and proposed plants based on current and emerging technologies, by September 30, 2010. Such report shall omit proprietary information and be prepared at reasonable cost.”

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEM NO. 6 FOR THE FOLLOWING REASONS:

The Company is a leader in the industry in developing technologies to reduce or eliminate carbon emissions in the generation of electric energy. This is best evidenced by its efforts to develop carbon capture and storage technologies and to construct two new nuclear units at Plant Vogtle. Through partnerships with the U.S. Department of Energy, the Electric Power Research Institute, and the Southeast Regional Carbon Sequestration Partnership, the Company is actively engaged in developing and deploying technology to reduce greenhouse gas emissions while ensuring that electricity remains reliable and affordable. The Company manages and operates the Department of Energy’s National Carbon Capture Center in Alabama, which is scheduled to be fully operational this year. For the past decade, the Company and the Department of Energy have been developing cleaner, less expensive, more reliable methods for power production from coal. This effort has resulted in the creation of a new process of gasification called Transport Integrated Gasification which not only matches, at a minimum, the environmental performance of very efficient gas-fired generation but also has the capability of capturing, in a more cost efficient way, a significant portion of the carbon dioxide emissions.

The Company does support greenhouse gas emissions reduction targets and has created a number of reports disclosing its actions related to carbon dioxide and other emissions. In January 2009, the Company signed onto principles developed by members of the Edison Electric Institute that outline a legislative solution to address the reduction of greenhouse gas emissions. These principles support near-term and mid-term (10 — 20 years) reductions in emissions based on the availability of technology and the use of energy efficiency, renewable energy, and new nuclear, and support a reduction target of 80% below current emissions levels by 2050. Also in 2009, the Company updated its report, Climate Change — A Summary of Southern Company Actions, on specific current and long-term activities to address carbon dioxide emissions. This report is updated on an annual basis. This report is one of several produced by the Company, including, in 2005, the Environmental Assessment: Report to Shareholders, outlining options and actions the Company is taking with regard to carbon dioxideand other emissions, including an extensive review of carbon dioxideprice scenarios; in 2006, and updated periodically since then, its Corporate Responsibility Report, which includes data on emissions and actions being undertaken to address those emissions; and in 2008, Energy Efficiency Regulatory Structures, discussing the need for and the impacts of energy efficiency efforts as a resource to meet growth and regulatory structures.

These reports are available either through the Company’s external website at www.southerncompany.com or by contacting Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308 and requesting a copy.

The vote needed to pass the proposed stockholders’ resolution is a majority of the shares represented at the meeting and entitled to vote.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEM NO. 6.

ITEM NO. 7 — STOCKHOLDER PROPOSAL ON COAL COMBUSTION BYPRODUCTS ENVIRONMENTAL REPORT

The Company has been advised that Green Century Capital Management, Inc., 114 State Street, Suite 200, Boston, Massachusetts 02109, holder of 120 shares of Common Stock, proposes to submit the following resolution at the 2010 Annual Meeting of Stockholders.

“Whereas: Coal combustion waste (CCW) is a by-product of burning coal that contains high concentrations of arsenic, mercury, heavy metals and other toxins filtered out of smokestacks by pollution control equipment. CCW is often stored in landfills, impoundment ponds or abandoned mines. Over 130 million tons of CCW are generated each year in the U.S.

“Coal combustion comprises a significant portion (68%) of Southern Company’s generation capacity.

“The toxins in CCW have been linked to cancer, organ failure, and other serious health problems. In October 2009, the U.S. Environmental Protection Agency (EPA) published a report finding that ‘Pollutants in coal combustion wastewater are of particular concern because they can occur in large quantities (i.e., total pounds) and at high concentrations...in discharges and leachate to groundwater and surface waters.’

“The EPA has found evidence at over 60 sites in the U.S. that CCW has polluted ground and surface waters.

“Recent reports by the New York Times and others have drawn attention to CCW’s impact on the nation’s waterways, as a result of leaking CCW storage sites or direct discharge into surrounding rivers and streams.

“The Tennessee Valley Authority’s (TVA) 1.1 billion gallon CCW spill in December 2008 that covered over 300 acres in eastern Tennessee with toxic sludge highlights the serious environmental risks associated with CCW. TVA estimates a total cleanup cost of $1.2 billion. This figure does not include the legal claims that have arisen in the spill’s aftermath.

“Our company also re-uses a significant portion of its CCW. While dry CCW has beneficial re-uses, such as in concrete and pavement, it can also pose public health and environmental risks in the dry form.

“The EPA plans to determine by the end of 2009 whether certain power plant by-products such as coal ash should be treated as hazardous waste, which would subject CCW to stricter regulations.

“The EPA has identified over 580 CCW impoundment facilities around the country. At least 49 of these have been rated by the National Inventory of Dams (NID) as ‘high hazard potential’ sites, where a dam breach would likely result in a loss of human life and significant environmental consequences. According to our company’s filings with the EPA, our company operates at least 18 CCW impoundments. One of these ponds, operated by Georgia Power, has been labeled ‘high hazard potential’ by the NID.

“Our company has withheld information about inspections and size of its ponds as confidential, despite disclosure of inspection information by all other responding companies, keeping shareholders in the dark about possible risks.

“RESOLVED: Shareholders request that the Board prepare a report on the company’s efforts, above and beyond current compliance, to reduce environmental and health hazards associated with coal combustion waste, and how those efforts may reduce legal, reputational and other risks to the company’s finances and operations. This report should be available to shareholders by August 2010, be prepared at reasonable cost, and omit confidential information such as proprietary data or legal strategy.”

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEM NO. 7 FOR THE FOLLOWING REASONS:

The Company’s affiliates have an extensive system in place to ensure the safe and proper management of coal combustion byproducts (CCBs). In addition, a significant amount of CCBs from the Company’s affiliates’ coal-based power generation plants, including coal ash and gypsum, is recycled for safe and beneficial uses such as concrete production and road building. The Company has prepared a report to provide an overview of its affiliates’ production and management of CCBs from electricity generation. The report includes relevant information on the Company’s affiliates’ operations related to CCBs, as well as the broad range of steps taken to ensure that the priorities of public safety and the security of the Company’s affiliates’

plants are met. The report details the Company’s affiliates’ operations, including how the CCBs are generated, the procedures for safe handling, the beneficial use market, and research efforts. The Company has posted the report on its website. The Company has also provided extensive, detailed information about its affiliates’ management of CCBs to the U.S. Environmental Protection Agency (EPA). This information is being released to the public on the EPA website (http://www.epa.gov /waste/nonhaz/industrial/special/fossil/surveys/index.htm). Additionally, the Company posts on its website its Corporate Responsibility Report which was created in 2006 and is updated periodically with new information. The Corporate Responsibility Report also includes a section on CCBs, including information on the management and beneficial use of CCBs. CCBs are recycled and used as an ingredient in common, everyday products. The success of the Company’s affiliates’ beneficial use programs reduces landfill obligations by more than 1.5 million tons annually. The beneficial use of CCBs has many associated environmental benefits, including a reduction in energy consumption, greenhouse gases, need for additional landfill space, and raw material consumption. The characteristics of CCBs enable beneficial uses and management to be undertaken safely. The concentration of metals in CCBs that occurs naturally in coal in trace amounts is not comparable to levels found in other substances that are required to be regulated as hazardous. While the Company’s affiliates have focused recent efforts on the beneficial use of CCBs, they have safely managed the remaining byproducts at their respective plants for decades. The Company’s affiliates have a robust program in place to ensure the safety and integrity of dams and dikes at on-site surface impoundments. They are inspected at least every week by trained plant personnel and inspected at least every year by professional dam safety engineers. The Company has managed nearly $500 million in research and development over the past decade, including several projects to find new and innovative ways to beneficially use CCBs.

The Company-produced reports are available either through the Company’s external website at www.southerncompany.com or by contacting Melissa K. Caen, Assistant Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308 and requesting a copy.

The vote needed to pass the proposed stockholder’s resolution is a majority of the shares represented at the meeting and entitled to vote.

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEM NO. 7.

Audit Committee Report

The Audit Committee oversees the Company’s financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for establishing and maintaining adequate internal controls over financial reporting, including disclosure controls and procedures, and for preparing the Company’s consolidated financial statements. In fulfilling its oversight responsibilities, the Audit Committee reviewed the audited consolidated financial statements of the Company and its subsidiaries and management’s report on the Company’s internal control over financial reporting in the 2009 Annual Report to Stockholders attached hereto as Appendix C with management. The Audit Committee also reviews the Company’s quarterly and annual reporting on Forms 10-Q and 10-K prior to filing with the SEC. The Audit Committee’s review process includes discussions of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and estimates and the clarity of disclosures in the financial statements.

The independent registered public accounting firm is responsible for expressing opinions on the conformity of the consolidated financial statements with accounting principles generally accepted in the United States and the effectiveness of the Company’s internal control over financial reporting with the criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Audit Committee has discussed with the independent registered public accounting firm the matters that are required to be discussed by Statement on Auditing Standards No. 61, as amended (American Institute of Certified Public Accountants, Professional Standards, Vol. 1, AU Section 380), as adopted by the Public Company Accounting Oversight Board (PCAOB) in Rule 3200T. In addition, the Audit Committee has discussed with the independent registered public accounting firm its independence from management and the Company as required under rules of the PCAOB and has received the written disclosures and letter from the independent registered public accounting firm required by the rules of the PCAOB. The Audit Committee also has considered whether the independent registered public accounting firm’s provision of non-audit services to the Company is compatible with maintaining the firm’s independence.

The Audit Committee discussed the overall scopes and plans with the Company’s internal auditors and independent registered public accounting firm for their respective audits. The Audit Committee meets with the internal auditors and the independent registered public accounting firm, with and without management present, to discuss the results of their audits, evaluations by management and the independent registered public accounting firm of the Company’s internal control over financial reporting, and the overall quality of the Company’s financial reporting. The Audit Committee also meets privately with the Company’s compliance officer. The Committee held 10 meetings during 2009.

In reliance on the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors (and the Board approved) that the audited consolidated financial statements be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and filed with the SEC. The Audit Committee also reappointed Deloitte & Touche as the Company’s independent registered public accounting firm for 2010. Stockholders will be asked to ratify that selection at the Annual Meeting of Stockholders.

Members of the Audit Committee:

William G. Smith, Jr., Chair
Jon A. Boscia
Warren A. Hood, Jr.

Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS (CD&A)

GUIDING PRINCIPLES AND POLICIES

The Company’s 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.

Our executive compensation program places significant focus on rewarding performance. The program is performance-based in several respects:


•	Our actual earnings per share (EPS) and business unit performance, which includes return on equity (ROE) or net income, compared to target performance levels established early in the year, determine the actual payouts under the short-term (annual) performance-based compensation program (Performance Pay Program).

•	Common Stock price changes result in higher or lower ultimate values of stock options.

•	Our dividend payout and total shareholder return compared to those of our industry peers lead to higher or lower payouts under the Performance Dividend Program (performance dividends).

In support of our performance-based pay philosophy, we have no general employment contracts with our named executive officers or guaranteed severance, except upon a change in control.

Our pay-for-performance principles apply not only to the named executive officers, but to thousands of employees. Our Performance Pay Program covers almost all of our nearly 26,000 employees. Our stock options and performance dividends cover approximately 7,000 employees. These programs engage our people in our business, which ultimately is good not only for them, but for our customers and our stockholders.

OVERVIEW OF EXECUTIVE COMPENSATION COMPONENTS

Our executive compensation program has 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.


	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.


	Intended Role and What the Element
Pay Element	Rewards	Why We Use the Element


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 stockholders.

Long-Term Performance-Based Compensation: Performance Dividends	Performance dividends provide cash compensation dependent on the number of stock options held at year end, the Common Stock dividends paid during the year, and the 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 stockholders. Aligns executives’ interests with stockholders’ interests since payouts are dependent on the returns realized by our stockholders versus those of our industry peers.

Retirement Benefits	The Southern Company Deferred Compensation Plan provides the opportunity to defer to future years up to 50% of base salary and all or part of 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 the Company, including a 401(k) savings plan and the funded Southern Company Pension Plan (Pension Plan). 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.	Market practice. Permitting compensation deferral is a cost-effective method of providing additional cash flow to the Company 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. Represents an important component of competitive market-based compensation in both our peer group and generally.

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 Towers Perrin’s database. Those companies are drawn from this list of primarily regulated utilities of $2 billion in revenues and up.




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.

The Company is one of the largest utility companies in the United States 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.

As an additional reference, the Compensation Committee reviewed the compensation disclosed for the chief executive officers of the 24 largest utilities in terms of revenue. The consultant obtained this information from each of the following companies’ 2009 proxy filings.



Ameren Corporation		FirstEnergy Corp.
American Electric Power Company, Inc.		FPL Group, Inc.
CenterPoint Energy, Inc.		Integrys Energy Company, Inc.
CMS Energy Corporation		Nisource Inc.
Consolidated Edison, Inc.		Northeast Utilities
Constellation Energy Group, Inc.		Pepco Holdings, Inc.
Dominion Resources Inc.		PG&E Corporation
DTE Energy		PPL Corporation
Duke Energy Corporation		Progress Energy, Inc.
Edison International		Public Service Enterprise Group, Inc.
Entergy Corporation		Sempra Energy
Exelon Corporation		Xcel Energy Inc.

In using this market data, market is defined as the size-adjusted 50th percentile of the survey data, with a focus on pay opportunities at target performance (rather than actual plan payouts). The Company specifically looks at the 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. Based on that data, the Company recommends to the Compensation Committee a total target compensation opportunity 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, our compensation program is designed to result in payouts that are market-appropriate given our performance for the year or period.

The Company 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. At the beginning of 2009, all of the named executive officers were below the median of the above-described market data. The Compensation Committee adjusted the target long-term performance-based compensation value to bring the total target compensation levels to the median of the market. Except for Mr. Ratcliffe, the total target compensation levels of the named executive officers increased in 2009. The decrease in Mr. Ratcliffe’s total target compensation level was due primarily to the change in valuation of stock options as described below. With the exception of a base salary increase for Mr. Bowers, as described below, no other changes to pay components were made in 2009. 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
	Salary		Compensation		Compensation		Opportunity
Name	($)		($)		($)		($)


D. M. Ratcliffe		1,129,467		1,129,467		4,913,181		7,172,115

W. P. Bowers		599,004		449,253		1,347,756		2,396,013

T. A. Fanning		664,685		498,514		1,256,252		2,419,451

M. D. Garrett		695,402		521,552		1,279,539		2,496,493

C. D. McCrary		662,242		496,681		1,185,412		2,344,335

For purposes of comparing the value of our compensation program to the market data, stock options are valued at 5.7%, and performance dividend targets at 10%, of the average daily Common Stock price for the year preceding the 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 targets established for the 2009-2012 performance-measurement period, this value was $4.94 per stock option granted. In the long-term incentive 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 incentive 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 any 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, Towers Perrin analyzed the level of actual payouts, for 2007 performance, under the annual Performance Pay Program to the named executive officers relative to performance versus our peer companies to provide a check on the Company’s goal-setting process. The findings from the analyses were used in establishing performance goals and the

associated range of payouts for goal achievement for 2009. That analysis was updated in 2009 for 2008 performance, and those findings were used in establishing goals for 2010.

In 2008, the Compensation Committee received a detailed comparison of the Company’s executive benefits program to the benefits of a group of other large utilities and general industry companies. The results indicated that overall the Company’s executive benefits program was at market. Because this data does not change significantly year over year, the study is only updated every few years.

DESCRIPTION OF KEY COMPENSATION COMPONENTS

2009 Base Salary

Consistent with the broad-based compensation program for 2009, the Compensation Committee did not make any base salary adjustments for the named executive officers, except for Mr. Bowers. Because Mr. Bowers’ base salary was more than 10% below the median of the market data described above, Mr. Ratcliffe recommended a 6% salary increase, which was approved by the Compensation Committee.

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 our 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.

In 2009, we also focused on and rewarded:


•	EPS growth;

•	ROE in the top quartile of comparable electric utilities;

•	Dividend growth;

•	Long-term, risk-adjusted 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 achievement of these goals.

Mr. Ratcliffe, with the assistance of our Human Resources staff, recommended 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 the Company’s annual performance-based compensation program. Most employees of the Company, including the named executive officers, are participants for a total of almost 26,000 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, and inclusion. 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. Each of our business units has operational goals. For Messrs. Garrett and McCrary, the payout is adjusted up or down based on the operational goal results for Georgia Power and Alabama Power, respectively. For Messrs. Ratcliffe, Bowers, and Fanning, it is calculated using the corporate-wide weighted average of the operational goal results.

•	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.

•	Business unit financial performance is weighted at 50% of the financial goals. For our traditional utility operating companies (Alabama Power, Georgia Power, Gulf Power, and Mississippi Power), the business unit financial performance goal is ROE, which is defined as the operating company’s net income divided by average equity for the year. For each of our other business units, we establish financial performance measures that are tailored to such business unit.

For Messrs. Garrett and McCrary, the annual Performance Pay Program payout is calculated using the ROE for Georgia Power and Alabama Power, respectively. For Messrs. Ratcliffe, Bowers, and Fanning, it is calculated using a corporate-wide weighted average of all the business unit financial performance goals, including primarily each traditional operating company’s ROE. 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 non-recurring or 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 ($0.25 per share) to 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 the Company until its spin-off in April 2001. The settlement included an agreement by the 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 the Company’s current earnings are not sufficient to fund the Common Stock dividend at the same level or higher than the prior year.

Goal Details

Operational Goals:

Customer Satisfaction — The Company uses customer satisfaction surveys to evaluate its performance. The survey results provide an overall ranking for each traditional operating company, 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 — The 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 — We strived to manage total capital expenditures, excluding nuclear fuel, for the participating business units at or below $4.5 billion. If the capital expenditure target is exceeded, total operational goal performance is capped at 0.90 for all business units, regardless of the actual operational goal results. Adjustments to the goal may occur due to significant events not anticipated in the business plan established early in 2009, such as acquisitions or disposition of assets, new capital projects, and other events.

The ranges of performance levels established for the operational goals are detailed below.

Level of

Customer

Performance

Satisfaction

Reliability

Availability(%)

Safety

Inclusion

Maximum (1.10)

Top quartile for
each customer
segment

Improve historical performance

2.00

0.62 or top quartile

Significant improvement

Target (1.00)

Top quartile
overall

Maintain historical performance

2.75

0.988

Improve

Threshold (0.90)

2nd quartile
overall

Below
historical performance

3.75

1.373

Below expectations

0 Trigger

At or below median

Significant issues

6.00

Each quarter at threshold or below

Significant issues

EPS and Business Unit Financial Performance:

The range of EPS and ROE goals for 2009 is shown below. ROE goals vary 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 Below
								Payout Factor at		Threshold for
	EPS, excluding							Associated Level of		Operational
Level of	MCAR					Payout		Operational Goal		Goal
Performance	Settlement 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 set by the Compensation Committee at the beginning of 2009. Targets are set as a percentage of base salary. Mr. Ratcliffe’s target was set at 100%. For the other named executive officers, it was set at 75%. 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 Company’s financial statements in the 2009 Annual Report attached as Appendix C to this Proxy Statement (Financial Statements). EPS, as determined in accordance with accounting principles generally accepted in the United States and as reported in the Financial Statements, was $2.07 per share.


			EPS,					Business Unit
	Operational		excluding		EPS Goal			Financial		Total Weighted		Total
	Goal		MCAR		Performance			Performance		Financial		Payout
	Multiplier		Settlement		Factor		Business Unit	Factor		Performance		Factor
Name	(A)		Impact		(50% Weight)		Financial Performance	(50% Weight)		Factor (B)		(A x B)

D. M. Ratcliffe		1.08	$	2.32		0.57	Corporate-wide weighted average		0.90		0.73		0.79

W. P. Bowers		1.08	$	2.32		0.57	Corporate-wide weighted average		0.90		0.73		0.79

T. A. Fanning		1.08	$	2.32		0.57	Corporate-wide weighted average		0.90		0.73		0.79

M. D. Garrett		1.06	$	2.32		0.57	11.01% ROE		0.01		0.29		0.30

C. D. McCrary		1.09	$	2.32		0.57	13.27% ROE		1.57		1.07		1.17

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.

Except for performance at Alabama Power, actual performance, as adjusted, was below the target performance levels established by the Compensation Committee in early 2009; therefore, the payout levels for all of the named executive officers, except Mr. McCrary, were below the target pay opportunities that were established. More information on how the 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		Actual Annual
	Performance Pay Program		Performance Pay Program
Name	Opportunity ($)		Payout ($)


D. M. Ratcliffe		1,129,467		892,279

W. P. Bowers		449,253		354,910

T. A. Fanning		498,514		393,826

M. D. Garrett		521,552		156,466

C. D. McCrary		496,681		581,117

Stock Options

Stock options are granted annually and were granted in 2009 to the named executive officers and about 7,000 other employees. 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 the Company, including the named executive officers. For the grants made in 2009, unvested options are forfeited if the executive officer retires from the Company 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 any executive officer who accepts a position with a peer company.

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. 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.


	Long-Term		Value Per		Number of Stock
Name	Value ($)		Stock Option ($)		Options Granted


D. M. Ratcliffe		4,913,181		4.94		994,571

W. P. Bowers		1,347,756		4.94		272,825

T. A. Fanning		1,256,252		4.94		254,302

M. D. Garrett		1,279,539		4.94		259,016

C. D. McCrary		1,185,412		4.94		239,962

More information about the stock option program is contained in the Grants 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 our 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, the 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 the 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 option held at December 31, 2009, based on performance during the 2006-2009 performance-measurement period. Payout for performance between points was interpolated on a straight-line basis.


	Payout (% of Each
Performance vs. Peer Group	Quarterly Dividend Paid)


90th percentile or higher		100

50th percentile (Target)		50

10th percentile or lower		0

For tax purposes, the Compensation Committee approved a payout for the named executive officers of up to 0.6% of the Company’s average net income over the performance-measurement period and used negative discretion to arrive at a payout commensurate with the scale shown.

The 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

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.


	Payout (% of Each
Performance vs. Peer Groups	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, EPS and business unit financial performance goals for the 2009 annual 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 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 the Company 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 page 33 of this CD&A.) See the Pension Benefits table and the information accompanying it for more information about pension-related benefits.

The Company 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 officers 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 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 the Company 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 three times their base salary plus the annual Performance Pay Program amount assuming target-level performance. Less than 15 officers of the Company and its subsidiaries, including all of the named executive officers, are entitled to this level of severance payment. Most other officers of the Company and its subsidiaries were entitled to severance payments equal to two times their base salary plus the annual Performance Pay Program amount assuming target-level performance. These amounts were consistent with that provided by other companies of our size and in our industry based on market data provided to the Compensation Committee from its compensation consultant.

However, based on the review conducted in 2009, the Compensation Committee made changes to our program. Notably, the following changes were approved:


•	Elimination of the highest-level severance payment except for the Company’s Chief Executive Officer and Chief Operating Officer. (Current participants, which include all of the named executive officers, are not affected.)

•	Reduction of severance payment level from three times base salary plus target Performance Pay Program opportunity to two times that amount for all other executive officers of the Company and reduction from two times to one times base salary plus target Performance Pay Program opportunity for all other officers of the Company and its subsidiaries. (Current executive officers of the Company are not affected; effective immediately for all other officers.)

•	Elimination of excise tax gross-up for all participants. (Current eligible participants, less than 15 officers, including all of the named executive officers, are not affected.)

•	Elimination of program for all non-officers. (Effective immediately.)

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 the 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 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 Company-sponsored plans, and Common Stock accounts in the Deferred Compensation Plan and the Supplemental Benefit Plan. One-third of vested stock options may be counted, but, if so, the ownership requirement is doubled. The ownership requirement is reduced by one-half at age 60. Messrs Garrett and Ratcliffe are over age 60.

The requirements are expressed as a multiple of base salary per the table below.


	Multiple of Salary without	Multiple of Salary Counting
Name	Counting Stock Options	1/3 of Vested Options


D. M. Ratcliffe	2.5 Times	5 Times

W. P. Bowers	3 Times	6 Times

T. A. Fanning	3 Times	6 Times

M. D. Garrett	1.5 Times	3 Times

C. D. McCrary	3 Times	6 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.

Impact of Accounting and Tax Treatments on Compensation

Section 162(m) of the Internal Revenue Code of 1986, as amended (Code), limits the tax deductibility of each named executive officer’s compensation that exceeds $1 million per year unless the compensation is paid under a performance-based plan as defined in the Code that has been approved by stockholders. The Company has obtained stockholder approval of the Omnibus Incentive Compensation Plan, under which most of our performance-based compensation is paid. For tax purposes, in order to ensure that annual performance-based compensation and performance dividend payouts are fully deductible under Section 162(m) of the Code, in February 2009, the Compensation Committee approved a formula that represented a maximum annual performance-based compensation amount payable and the maximum performance dividend amount payable for the 2009-2012 performance-measurement period. For 2009 performance, the Compensation Committee used (for annual performance-based compensation), or will use (for performance dividends), negative discretion from those amounts to determine the actual payouts pursuant to the methodologies described above. Because our policy is to maximize long-term stockholder value, as described fully in this CD&A, tax deductibility is not the only factor considered in setting compensation.

Policy on Recovery of Awards

The Company’s Omnibus Incentive Compensation Plan provides that, if the Company 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 the Company 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.

Company Policy Regarding Hedging the Economic Risk of Stock Ownership

The Company’s policy is that insiders, including outside directors, will not trade in 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 the Company, 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 the three-year performance-measurement period, the number of units will be adjusted up or down (zero to 200%) based on the 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 those currently used for performance dividends.) 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 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. The number of stock options used to calculate these payouts will be limited to the number of stock options 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 Board of Directors that the CD&A be included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and in this Proxy Statement. The 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

SUMMARY COMPENSATION TABLE

The Summary Compensation Table shows the amount and type of compensation received or earned in 2007, 2008, and 2009 by the Chief Executive Officer, the Chief Financial Officer, and the next three most highly-paid executive officers of the Company who served in 2009. Collectively, these five officers are referred to as the “named executive officers.”


													Change in
													Pension Value
													and
											Non-Equity		Nonqualified
											Incentive		Deferred
							Stock		Option		Plan		Compensation		All Other
Name and Principal			Salary		Bonus		Awards		Awards		Compensation		Earnings		Compensation		Total
Position	Year		($)		($)		($)		($)		($)		($)		($)		($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)

David M. Ratcliffe		2009		1,172,908						1,790,228		5,019,745		2,745,370		76,223		10,804,474
Chairman, President,		2008		1,118,090		—		—		1,666,774		5,267,878		1,481,217		79,378		9,613,337
& CEO		2007		1,068,268		—		—		2,215,880		2,901,883		4,683,305		88,585		10,957,921


W. Paul Bowers		2009		614,870						491,085		967,334		931,232		44,410		3,048,931
Executive Vice		2008		557,476		56,510		—		201,808		1,001,174		185,472		770,837		2,773,277
President & CFO		2007		502,366		—		—		291,202		669,586		582,095		42,282		2,087,531


Thomas A. Fanning		2009		690,250						457,744		1,086,911		927,301		38,432		3,200,638
Executive Vice		2008		658,246		—		—		237,374		1,348,981		235,664		49,341		2,529,606
President & COO		2007		610,624		—		—		409,454		954,988		814,123		43,658		2,832,847


Michael D. Garrett		2009		722,149						466,229		847,998		1,701,049		47,587		3,785,012
President, Georgia		2008		679,641		—		—		248,343		1,283,734		666,453		48,411		2,926,582
Power Company		2007		613,731		—		—		413,075		828,844		2,259,654		47,440		4,162,744


Charles D. McCrary		2009		687,713						431,932		1,350,171		1,195,625		48,375		3,713,816
President, Alabama		2008		656,209		—		—		236,500		1,287,318		639,855		57,386		2,877,268
Power Company		2007		629,961		—		—		421,612		983,174		1,156,038		58,132		3,248,917

Column (e)

No equity-based compensation has been awarded to the named executive officers, other than Option Awards which are reported in column (f).

Column (f)

This column reports the aggregate grant date fair value of stock option grants made during the applicable year, disregarding any estimates of forfeitures related to service-based vesting conditions. See Note 8 to the Financial Statements for a discussion of the assumptions used in calculating these amounts.

Column (g)

The amounts in this column are the aggregate of the payouts under the Performance Pay Program and the Performance Dividend Program attributable to performance periods ended December 31, 2009 that are discussed in the CD&A. The amounts paid under each program to the named executive officers are shown below.


	Annual
	Performance-Based		Performance
	Compensation		Dividends		Total
Name	($)		($)		($)

D. M. Ratcliffe		892,279		4,127,466		5,019,745

W. P. Bowers		354,910		612,424		967,334

T. A. Fanning		393,826		693,085		1,086,911

M. D. Garrett		156,466		691,532		847,998

C. D. McCrary		581,117		769,054		1,350,171

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 the Company measured its retirement benefit obligations for accounting purposes. Starting in 2008, the 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 the Company selected for cost purposes as of that measurement date; however, the named executive officers were assumed to remain employed at any subsidiary of the Company 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 that were made in 2007 regarding the form and timing of payments from the supplemental pension plans. Those 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 spouse, these plans will pay the single sum value of those benefits for an average lifetime in 10 annual installments. The present value of accumulated benefits prior to September 30, 2007 reflects supplemental pension benefits being paid monthly for the lifetimes of the 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.

This column also reports any above-market earnings on deferred compensation under the Deferred Compensation Plan (DCP); however, there were no above-market earnings on deferred compensation in 2009. For more information about the DCP, see the Nonqualified Deferred Compensation table and the information accompanying it.

The table below itemizes the amounts reported in this column.


					Above-Market
			Change in		Earnings on Deferred
			Pension Value		Compensation		Total
Name	Year		($)		($)		($)

D. M. Ratcliffe		2009		2,745,370		0		2,745,370
		2008		1,481,217		0		1,481,217
		2007		4,646,301		37,004		4,683,305

W. P. Bowers		2009		931,232		0		931,232
		2008		185,472		0		185,472
		2007		577,633		4,462		582,095

T. A. Fanning		2009		927,301		0		927,301
		2008		235,664		0		235,664
		2007		809,570		4,553		814,123

M. D. Garrett		2009		1,701,049		0		1,701,049
		2008		666,453		0		666,453
		2007		2,250,828		8,826		2,259,654

C. D. McCrary		2009		1,195,625		0		1,195,625
		2008		639,855		0		639,855
		2007		1,150,499		5,539		1,156,038

Column (i)

This column reports the following items: perquisites, Company 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 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 for 2009 are itemized below.


	Perquisites		ESP		SBP		Total
Name	($)		($)		($)		($)

D. M. Ratcliffe		17,114		11,786		47,323		76,223

W. P. Bowers		13,419		12,128		18,863		44,410

T. A. Fanning		4,143		11,581		22,708		38,432

M. D. Garrett		10,757		12,495		24,335		47,587

C. D. McCrary		15,236		10,561		22,578		48,375

Description of Perquisites

Personal Financial Planning is provided for most officers of the Company, including all of the named executive officers. The Company pays for the services of the financial planner on behalf of the officers, up to a maximum amount of $9,780 per year, after the initial year that the benefit is provided. The Company also provides a five-year allowance of $6,000 for estate planning and tax return preparation fees.

Home Security Monitoring is provided by or under the direction of the Company’s security personnel. The amount of the benefit reported here represents the incremental cost of the Company-provided monitoring or the actual amount paid to a third-party provider, as applicable. For the Company-provided monitoring, the incremental cost is the full cost of providing security monitoring at Company-owned facilities and covered employees’ residences divided by the number of security systems monitored.

GRANTS OF PLAN-BASED AWARDS IN 2009

This table provides information on stock option grants made and goals established for future payouts under the Company’s performance-based compensation programs during 2009 by the Compensation Committee. In this table, the annual Performance Pay Program and the performance dividend amounts are referred to as PPP and PDP, respectively.


										All Other
										Option				Grant Date
										Awards:		Exercise		Fair
										Number of		or Base		Value of
				Estimated Possible Payouts Under						Securities		Price of		Stock and
				Non-Equity Incentive Plan Awards						Underlying		Option		Option
	Grant			Threshold		Target		Maximum		Options		Awards		Awards
Name	Date			($)		($)		($)		(#)		($/Sh)		($)
(a)	(b)			(c)		(d)		(e)		(f)		(g)		(h)

D. M. Ratcliffe		2/16/2009	PPP		10,165		1,129,467		2,484,827
		2/16/2009	PDP		162,284		3,245,689		6,491,379		994,571		31.39		1,790,228


W. P. Bowers		2/16/2009	PPP		4,043		449,253		988,357
		2/16/2009	PDP		24,079		481,588		963,176		272,825		31.39		491,085


T. A. Fanning		2/16/2009	PPP		4,487		498,514		1,096,731
		2/16/2009	PDP		27,251		545,017		1,090,033		254,302		31.39		457,744


M. D. Garrett		2/16/2009	PPP		4,694		521,552		1,147,414
		2/16/2009	PDP		27,190		543,795		1,087,590		259,016		31.39		466,229


C. D. McCrary		2/16/2009	PPP		4,470		496,681		1,092,698
		2/16/2009	PDP		30,238		604,756		1,209,512		239,962		31.39		431,932

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 Company’s annual Performance Pay Program. The Compensation Committee assigns each named executive officer a target incentive opportunity, expressed as a percentage of base salary as detailed in the CD&A. The amount paid to each named executive officer under the annual 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 program, including the applicable performance criteria established by the Compensation Committee, is provided in the CD&A.

The Company also has a long-term performance-based compensation program, the Performance Dividend Program, that pays performance-based dividend equivalents based on the 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, if any, 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 of the final year of the performance-measurement period. Also, nothing is earned unless the Company’s earnings are sufficient to fund a Common Stock dividend at the same level or higher than in the prior year.

The Performance Dividend Program pays to all option holders a percentage of the Common Stock dividend paid to 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 the Company’s TSR is at or above the 90th percentile. That amount is then paid per option held at the end of the four-year performance-measurement 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) the Company’s TSR compared to that of its peer companies as of December 31, 2012, (2) the actual dividend, if any, paid in 2012 to our stockholders, and (3) the number of options granted prior to 2010 held by the option holders on December 31, 2012.

The number of options held on December 31, 2012 will be affected by the number of options, if any, exercised by the named executive officers prior to December 31, 2012. 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 2009 Fiscal Year-End table, and the Common Stock dividend of $1.73 per share paid to stockholders in 2009. These factors are itemized below.


	Stock Options		Performance Dividend		Performance Dividend		Performance Dividend
	Held as of		Per Option		Per Option		Per Option Paid at
	December 31,		Paid at Threshold		Paid at Target		Maximum
	2009		Performance		Performance		Performance
Name	(#)		($)		($)		($)


D. M. Ratcliffe		3,752,242		0.04325		0.86500		1.7300

W. P. Bowers		556,749		0.04325		0.86500		1.7300

T. A. Fanning		630,077		0.04325		0.86500		1.7300

M. D. Garrett		628,665		0.04325		0.86500		1.7300

C. D. McCrary		699,140		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 16, 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, which was February 13, 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.

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.


	Option Awards							Stock Awards
											Equity
											Incentive
											Plan
										Equity	Awards:
					Equity					Incentive	Market or
					Incentive					Plan	Payout Value
					Plan				Market	Awards:	of Unearned
					Awards:			Number of	Value	Number of	Shares,
	Number of		Number of		Number of			Shares or	of Shares	Unearned	Units
	Securities		Securities		Securities			Units of	or Units	Shares,	or Other
	Underlying		Underlying		Underlying			Stock	of Stock	Units or	Rights
	Unexercised		Unexercised		Unexercised	Option		That	That Have	Other Rights	That Have
	Options		Options		Unearned	Exercise	Option	Have Not	Not	That Have	Not
	Exercisable		Unexercisable		Options	Price	Expiration	Vested	Vested	Not Vested	Vested
Name	(#)		(#)		(#)	($)	Date	(#)	($)	(#)	($)
(a)	(b)		(c)		(d)	(e)	(f)	(g)	(h)	(i)	(j)


D. M. Ratcliffe		92,521		0	—	25.26	02/15/2012	—	—	—	—
		82,265		0		29.50	02/13/2014
		273,031		0		29.315	08/02/2014
		550,000		0		32.70	02/18/2015
		518,739		0		33.81	02/20/2016
		358,557		179,278		36.42	02/19/2017
		234,427		468,853		35.78	02/18/2018
		0		994,571		31.39	02/16/2019


W. P. Bowers		60,576		0	—	32.70	02/18/2015	—	—	—	—
		67,517		0		33.81	02/20/2016
		47,120		23,560		36.42	02/19/2017
		28,384		56,767		35.78	02/18/2018
		0		272,825		31.39	02/16/2019


T. A. Fanning		80,843		0	—	32.70	02/18/2015	—	—	—	—
		95,392		0		33.81	02/20/2016
		66,255		33,127		36.42	02/19/2017
		33,386		66,772		35.78	02/18/2018
		0		254,302		31.39	02/16/2019


M. D. Garrett		17,806		0	—	29.50	02/13/2014	—	—	—	—
		52,376		0		32.70	02/18/2015
		94,420		0		33.81	02/20/2016
		66,841		33,420		36.42	02/19/2017
		34,929		69,857		35.78	02/18/2018
		0		259,016		31.39	02/16/2019


C. D. McCrary		71,424		0	—	29.50	02/13/2014	—	—	—	—
		86,454		0		32.70	02/18/2015
		99,178		0		33.81	02/20/2016
		68,222		34,111		36.42	02/19/2017
		33,263		66,526		35.78	02/18/2018
		0		239,962		31.39	02/16/2019

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

This table reports the number of shares acquired upon the exercise of stock options during 2009 and the value realized based on the difference in the market price over the exercise price on the exercise date.


	Option Awards				Stock Awards
	Number of Shares				Number of Shares
	Acquired on		Value Realized on		Acquired on	Value Realized on
	Exercise		Exercise		Vesting	Vesting
Name	(#)		($)		(#)	($)


D. M. Ratcliffe		0		0	0	0

W. P. Bowers		0		0	0	0

T. A. Fanning		90,529		435,518	0	0

M. D. Garrett		0		0	0	0

C. D. McCrary		0		0	0	0

PENSION BENEFITS AT 2009 FISCAL YEAR-END


		Number of		Present Value of		Payments
		Years Credited		Accumulated		During
		Service		Benefit		Last Fiscal Year
Name	Plan Name	(#)		($)		($)
(a)	(b)	(c)		(d)		(e)


D. M. Ratcliffe	Pension Plan		37.83		1,222,310	—
	Supplemental Benefit Plan (Pension-Related)		37.83		13,216,934	—
	Supplemental Executive Retirement Plan		37.83		4,080,758	—

W. P. Bowers	Pension Plan		29.67		612,513	—
	Supplemental Benefit Plan (Pension-Related)		29.67		2,079,445	—
	Supplemental Executive Retirement Plan		29.67		698,539	—

T. A. Fanning	Pension Plan		28.00		569,414	—
	Supplemental Benefit Plan (Pension-Related)		28.00		2,613,276	—
	Supplemental Executive Retirement Plan		28.00		848,729	—

M. D. Garrett	Pension Plan		40.75		1,258,587	—
	Supplemental Benefit Plan (Pension-Related)		40.75		6,068,232	—
	Supplemental Executive Retirement Plan		40.75		1,971,338	—

C. D. McCrary	Pension Plan		35.00		968,854	—
	Supplemental Benefit Plan (Pension-Related)		35.00		4,332,918	—
	Supplemental Executive Retirement Plan		35.00		1,413,552	—

The named executive officers earn employer-paid pension benefits from three integrated retirement plans. More information about pension benefits is provided in the CD&A.

Pension Plan

The Pension Plan is a tax-qualified, funded plan. It is the 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 cash incentives paid during each year are 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. All of the named executive officers are 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.

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 6%. 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 a 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 highly-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 incentives 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


	•	Male retirees: 25% single life annuity; 25% level income annuity; 25% joint and 50% survivor annuity; and 25% joint and 100% survivor annuity
	•	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 incentive 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.

NONQUALIFIED DEFERRED COMPENSATION AS OF 2009 FISCAL YEAR-END


	Executive		Registrant					Aggregate
	Contributions		Contributions		Aggregate Earnings			Withdrawals/		Aggregate Balance
	in Last FY		in Last FY		in Last FY			Distributions		at Last FYE
Name	($)		($)		($)			($)		($)
(a)	(b)		(c)		(d)			(e)		(f)

D. M. Ratcliffe		0		47,323		(85,521	)		0		9,450,240

W. P. Bowers		369,101		18,863		52,656			0		1,481,038

T. A. Fanning		134,898		22,708		4,130			0		1,234,022

M. D. Garrett		0		24,335		25,222			0		1,355,526

C. D. McCrary		0		22,578		1,536			0		1,160,512

The 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, disability, 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 the Company from time to time. It provides participants with an equivalent opportunity for the capital appreciation (or loss) and income as that of a Company stockholder. During 2009, the rate of return in the Stock Equivalent Account was (4.83%), which was the 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 in The Wall Street Journal as 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 amount of performance-based compensation deferred in 2009 was the amount 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. This amount is 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 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 both on 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 (e)

There were no aggregate withdrawals or distributions.

Column (f)

This column includes amounts that were deferred under the DCP and contributions under the SBP in prior years and reported in prior years’ Proxy Statements. The chart below shows the amounts reported in prior years’ Proxy Statements.


			Employer Contributions
	Amounts Deferred under		under the SBP
	the DCP Prior to 2009		Prior to 2009 and
	and Reported in Prior		Reported in Prior Years’
	Years’ Proxy Statements		Proxy Statements		Total
Name	($)		($)		($)


D. M. Ratcliffe		5,381,881		292,081		5,673,962

W. P. Bowers		287,965		28,900		316,865

T. A. Fanning		838,422		103,938		942,360

M. D. Garrett		0		92,928		92,928

C. D. McCrary		489,924		172,851		662,775

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 the Company’s compensation and benefit programs or the change-in-control severance agreements with each of the named executive 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 Company’s 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 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 not for cause of a named executive officer who is not retirement-eligible.

•	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 the Company’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 Company or subsidiary level:


•	Southern Change in Control I — Acquisition by another entity of 20% or more of Common Stock or, following a merger with another entity, the Company’s stockholders own 65% or less of the entity surviving the merger.

•	Southern Change in Control II — Acquisition by another entity of 35% or more of Common Stock or, following a merger with another entity, the Company’s stockholders own less than 50% of the entity surviving the merger.


•	Southern Termination — A merger or other event and the Company is not the surviving company or Common Stock is no longer publicly traded.

•	Subsidiary Change in Control — Acquisition by another entity, other than another subsidiary of the Company, of 50% or more of the stock of a subsidiary of the Company, a merger with another entity and the subsidiary is not the surviving company, or the sale of substantially all the assets of the subsidiary.

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.

The following chart describes the treatment of different compensation and benefit elements in connection with the Traditional Termination Events described above. All of the named executive officers are eligible to retire under the terms of our pension benefits plans and therefore any termination of employment also would be a retirement.


		Lay Off
	Retirement/	(Involuntary			Involuntary
	Retirement-	Termination		Death or	Termination
Program	Eligible	Not For Cause)	Resignation	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 (DCP)	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 benefits administration committee’s discretion.	Same as Retirement.

Supplemental Benefit Plan (SBP) — non-pension related	Payable per prior elections (lump sum or up to 20 annual installments).	Same as Retirement.	Same as Retirement.	Same as the DCP.	Same as Retirement.

The chart below describes the treatment of payments under compensation and benefit programs under different change-in-control events. The Pension Plan, the DCP, and the SBP are not affected by change-in-control events.


				Involuntary
				Change-in-
				Control-Related
				Termination or
				Voluntary
			Southern	Change-in-
			Termination or	Control-Related
	Southern Change	Southern Change	Subsidiary Change	Termination
Program	in Control I	in Control II	in Control	for Good Reason


Nonqualified Pension Benefits	All SERP-related benefits vest if participant 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 Change in Control II.	Based on type of change-in-control event.

Annual Performance Pay Program	If program is not terminated, then is paid at greater of target or actual performance. If program is terminated within two years of change in control; pro-rated at target performance level.	Same as Southern Change in Control I.	Pro-rated at target performance level.	If not otherwise eligible for payment and if the program still in effect, pro-rated at target performance level.

Performance Dividend Program	If program is not terminated, then 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 Change in Control I.	Pro-rated at greater of actual or target performance level.	If not otherwise eligible for payment and if the program 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; if participant is an employee of a subsidiary, stock options vest upon a Subsidiary Change in Control.	Vest.


				Involuntary
				Change-in-
				Control-Related
				Termination or
				Voluntary
			Southern	Change-in-
			Termination or	Control-Related
	Southern Change	Southern Change	Subsidiary Change	Termination
Program	in Control I	in Control II	in Control	for Good Reason


Severance Benefits	Not applicable.	Not applicable.	Not applicable.	Three times base salary plus target annual performance-based program amount plus tax gross-up if severance amounts exceed 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 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 Retirement column are amounts that would have become payable to the named executive officers since all 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 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 present values of all the benefit 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.


				Resignation or		Death
				Involuntary Retirement		(payments
		Retirement		(monthly payments)		to a spouse)
Name		($)		($)		($)

D. M. Ratcliffe	Pension Plan		10,059		All plans treated as		5,251
	Supplemental Benefit Plan		1,577,122		retiring		1,577,122
	Supplemental Executive Retirement Plan		486,940				486,940

W. P. Bowers	Pension Plan		5,235		All plans treated as		4,147
	Supplemental Benefit Plan		298,809		retiring		298,809
	Supplemental Executive Retirement Plan		100,378				100,378

T. A. Fanning	Pension Plan		4,859		All plans treated as		3,912
	Supplemental Benefit Plan		376,239		retiring		376,239
	Supplemental Executive Retirement Plan		122,193				122,193

M. D. Garrett	Pension Plan		10,482		All plans treated as		5,690
	Supplemental Benefit Plan		748,194		retiring		748,194
	Supplemental Executive Retirement Plan		243,060				243,060

C. D. McCrary	Pension Plan		8,253		All plans treated as		4,945
	Supplemental Benefit Plan		569,145		retiring		569,145
	Supplemental Executive Retirement Plan		185,675				185,675

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 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	($)		($)		($)


D. M. Ratcliffe		15,771,216		4,869,398		20,640,615

W. P. Bowers		2,988,093		1,003,776		3,991,869

T. A. Fanning		3,762,394		1,221,935		4,984,328

M. D. Garrett		7,481,938		2,430,598		9,912,536

C. D. McCrary		5,691,453		1,856,754		7,548,208

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 1.3 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 these plans.

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, except for Mr. McCrary, the amount that would have been payable was the target level amount as reported in the Grants of Plan-Based Awards table. The amount for Mr. McCrary would have been the amount paid as reported in the Summary Compensation Table.

Performance Dividends

Because the assumed termination date is December 31, 2009, there is no additional amount that would be payable other than the amount 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.

Stock Options

Stock options would be treated as described in the Termination and Change-in-Control charts above. Under a Southern 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 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 Termination and the amount that would be payable under a Southern Termination if there were no conversion to the surviving company’s stock options.


					Total Payable in
			Total Number of		Cash
	Number of		Options Following		under a Southern
	Options with		Accelerated Vesting		Termination without
	Accelerated		under a Southern		Conversion of Stock
Name	Vesting (#)		Termination (#)		Options ($)


D. M. Ratcliffe		1,642,702		3,752,242		4,413,983

W. P. Bowers		353,152		556,749		564,109

T. A. Fanning		354,201		630,077		540,926

M. D. Garrett		362,293		628,665		600,393

C. D. McCrary		340,599		699,140		789,568

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

Because all of the named executive officers are retirement-eligible and health care benefits are provided to retirees, there is no incremental payment associated with the termination or change-in-control events.

Financial Planning Perquisite

All of the named executive officers are retirement-eligible; therefore, an additional year of the financial planning perquisite would be provided. That amount is set at a maximum of $9,780 per year.

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 Company has entered into individual Change-in-Control Severance Agreements with each of the named executive officers. 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 Company from any claims he may have against the 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 named executive officer’s base salary and target payout under the annual Performance Pay Program. If any portion of the severance payment is an “excess parachute payment” as defined under Section 280G of the Code, the Company will pay the named executive officer 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 any of the named executive officers because their respective estimated severance amounts payable are below the amounts considered excess parachute payments under the Code.


	Severance Amount
Name	($)


D. M. Ratcliffe		6,776,802

W. P. Bowers		3,144,771

T. A. Fanning		3,489,597

M. D. Garrett		3,650,862

C. D. McCrary		3,476,769

COMPENSATION PROGRAM RISK

The Compensation Committee considers risk when establishing compensation program goals and objectives. The Compensation Committee reviewed and discussed an assessment of the Company’s compensation policies and practices and concluded that excessive or inappropriate risk-taking is not encouraged, for the following reasons:


•	As described in detail in the CD&A, the Company’s total compensation program is a well-balanced mix of fixed (salary) and short- and long-term performance-based compensation (Performance Pay Program, stock options, and performance dividends) that reward based on financial and operational goals, stock price performance, and total shareholder return.
•	The annual pay/performance analysis conducted by the Compensation Committee’s consultant tests and influences our future goal-setting process.
•	The Company has strong compensation governance practices, including independent verification of financial goal achievement.
•	The Compensation Committee has established stock ownership requirements for all officers of the Company.
•	Our plan provisions require recoupment of awards under certain circumstances.

Other Information

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

No reporting person failed to file, on a timely basis, the reports required by Section 16(a) of the Securities Exchange Act of 1934, as amended.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Mr. Francis S. Blake, a former Director, and Mr. Donald M. James are the Chief Executive Officers of The Home Depot, Inc. and Vulcan Materials Company, respectively. During 2009, subsidiaries of the Company purchased goods and services in the amount of approximately approximately $502,000 from The Home Depot, Inc. and approximately $544,000 from Vulcan Materials Company. These amounts represented numerous individual purchases from The Home Depot, Inc. and several individual transactions with Vulcan Materials Company.

APPENDIX A

PROPOSED AMENDMENT TO THE COMPANY’S BY-LAWS

6. Each stockholder entitled to vote in accordance with the Certificate of Incorporation or any amendment thereof and in accordance with the provisions of these By-Laws or of any action taken pursuant thereto shall be entitled to one vote, in person or by proxy, for each share of stock entitled to vote held by such stockholder, but no proxy shall be voted on after three years from its date unless such proxy provides for a longer period. Except where the transfer books of the Corporation shall have been closed or a date shall have been fixed as a record date for the determination of its stockholders entitled to vote, as hereinafter provided, no share of stock shall be voted on at any election for directors which shall have been transferred on the books of the Corporation within 20 days next preceding such election of directors. The vote for directors, and, upon the demand of any stockholder, the vote upon any question before the meeting, shall be by ballot. Each director shall be elected by the vote of the majority of the votes cast with respect to the director at any meeting for the election of directors at which a quorum is present; provided that if the number of nominees exceeds the number of directors to be elected, directors shall be elected by a plurality vote and each stockholder shall be entitled to as many votes as shall equal the number of his shares of stock multiplied by the number of directors to be elected, and he may cast all of such votes for a single director or may distribute them among the number to be voted for, or any two or more of them as he may see fit, which right when exercised shall be termed cumulative voting. All other questions shall be decided by plurality vote except as otherwise provided by the Certificate of Incorporation and/or by the laws of the State of Delaware. For purposes of this Section 6, a majority of the votes cast means that the number of shares voted “for” the election of a director must exceed the number of votes cast “against” the election of that director.

APPENDIX B

POLICY ON ENGAGEMENT OF THE INDEPENDENT AUDITOR
FOR AUDIT AND NON-AUDIT SERVICES

Southern Company (including its subsidiaries) will not engage the independent auditor to perform any services that are prohibited by the Sarbanes-Oxley Act of 2002. It shall further be the policy of the Company not to retain the independent auditor for non-audit services unless there is a compelling reason to do so and such retention is otherwise pre-approved consistent with this policy. Non-audit services that are prohibited include:


	1.	Bookkeeping and other services related to the preparation of accounting records or financial statements of the Company or its subsidiaries.

	2.	Financial information systems design and implementation.

	3.	Appraisal or valuation services, fairness opinions, or contribution-in-kind reports.

	4.	Actuarial services.

	5.	Internal audit outsourcing services.

	6.	Management functions or human resources.

	7.	Broker or dealer, investment adviser, or investment banking services.

	8.	Legal services or expert services unrelated to financial statement audits.

	9.	Any other service that the Public Company Accounting Oversight Board determines, by regulation, is impermissible.


B.	Effective January 1, 2003, officers of the Company (including its subsidiaries) may not engage the independent auditor to perform any personal services, such as personal financial planning or personal income tax services.

C.	All audit services (including providing comfort letters and consents in connection with securities issuances) and permissible non-audit services provided by the independent auditor must be pre-approved by the Southern Company Audit Committee.

D.	Under this Policy, the Audit Committee’s approval of the independent auditor’s annual arrangements letter shall constitute pre-approval for all services covered in the letter.

E.	By adopting this Policy, the Audit Committee hereby pre-approves the engagement of the independent auditor to provide services related to the issuance of comfort letters and consents required for securities sales by the Company and its subsidiaries and services related to consultation on routine accounting and tax matters. The actual amounts expended for such services each calendar quarter shall be reported to the Committee at a subsequent Committee meeting.


F.	The Audit Committee also delegates to its Chairman the authority to grant pre-approvals for the engagement of the independent auditor to provide any permissible service up to a limit of $50,000 per engagement. Any engagements pre-approved by the Chairman shall be presented to the full Committee at its next scheduled regular meeting.


G.	The Southern Company Comptroller shall establish processes and procedures to carry out this Policy.

Approved by the Southern Company Audit Committee
December 9, 2002

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 in Internal Control — Integrated Framework issued 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 C-1). 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 C-32 to C-85) 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 in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 25, 2010

C-2

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).

C-3

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%.

C-4

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	%

C-5

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

C-6

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.

C-7

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.

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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.

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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

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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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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
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%.

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 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 than ¹/2 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

C-25

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.

C-26

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.

C-27

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.

C-28

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.

C-29

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.

C-30

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.

C-31

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.

C-32

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.

C-33

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.

C-34

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.

C-35

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

$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

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

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.

C-37

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.

C-38

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.

C-40

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.

C-41

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.

C-42

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

C-43

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.

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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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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

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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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.

Carbon Dioxide Litigation

New York Case

Kivalina Case

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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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.

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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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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NOTES (continued)
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 approximately ¹/2 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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Southern Company and Subsidiary Companies 2009 Annual Report

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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Southern Company and Subsidiary Companies 2009 Annual Report

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

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Southern Company and Subsidiary Companies 2009 Annual Report

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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Southern Company and Subsidiary Companies 2009 Annual Report

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

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

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week 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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NOTES (continued)
Southern Company and Subsidiary Companies 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	$	—	$	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

As of December 31, 2009:

Value

Commitments

Frequency

Notice Period

(in millions)

Nuclear decommissioning trusts:

Corporate bonds – commingled funds

None

Daily

1 to 3 days

Other – commingled funds

None

Daily

Not applicable

Trust owned life insurance

None

Daily

15 days

Cash equivalents and restricted cash:

Money market funds

623

None

Daily

Not applicable

Other:

Deferred compensation — money market funds

None

Daily

Not applicable

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Southern Company and Subsidiary Companies 2009 Annual Report

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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Southern Company and Subsidiary Companies 2009 Annual Report

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.

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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

Net

Longest

Net Sold

Hedge

Non-Hedge

Purchased

Hedge

Non-Hedge

Megawatt-hours

Date

mmBtu

Date

(in millions)

2.6

2010

154

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.

C-82

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

C-83

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.

C-84

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

C-85

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

C-87

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

C-88

MANAGEMENT COUNCIL

1. David M. Ratcliffe
Chairman, President, and CEO

Ratcliffe, 61, joined the Company as a biologist with Georgia Power in 1971 and has been in his current position since 2004. From 1999 to 2004, he was president and CEO of Georgia Power, Southern Company’s largest subsidiary, and from 1991 to 1995 he served as president and CEO of Mississippi Power. Ratcliffe has held executive and management positions in the areas of finance, external affairs, fuel services, operations and planning, and research and environmental affairs.

2. W. Paul Bowers

Executive Vice President and
Chief Financial Officer

Bowers, 53, joined the Company as a residential sales representative with Gulf Power in 1979. He has held his current position since 2008. Previously, he served as president of Southern Company Generation. He also served as president and CEO of Southern Power, president and CEO of Southern Company’s former United Kingdom subsidiary, and senior vice president and chief marketing officer for Southern Company and held executive positions at Georgia Power.

3. Thomas A. Fanning

Executive Vice President and
Chief Operating Officer

Fanning, 53, joined the Company as a financial analyst in 1980. In his current position since 2008, Fanning is responsible for Southern Company Generation, Southern Power, and Southern Company Transmission, as well as leading Southern Company’s efforts on business strategy and associated planning issues. He has served as president and CEO of Gulf Power and chief financial officer for both Southern Company, Georgia Power, and Mississippi Power.

4. Michael D. Garrett

Executive Vice President
President and CEO, Georgia Power

Garrett, 60, joined the Company as a cooperative-education student with Georgia Power in 1968. He assumed his current position in 2004. Previously, Garrett was president and CEO of Mississippi Power. He has held executive positions at Alabama Power in customer operations, regulatory affairs, finance, and external affairs and also served as Birmingham Division vice president.

5. G. Edison Holland, Jr.

Executive Vice President, General Counsel,
and Corporate Secretary

Holland, 57, joined the Company as vice president and corporate counsel for Gulf Power in 1992. He was named to his current position, which includes serving as the chief compliance officer, in 2001. Previously, he was president and CEO of Savannah Electric and vice president of power generation and transmission at Gulf Power.

6. C. Alan Martin

Executive Vice President
President and CEO, Southern Company Services

Martin, 61, joined the Company as a right-of-way agent at Alabama Power in 1972. He has held his current position since 2008. Martin previously served as executive vice president and chief marketing officer for Southern Company, as well as vice president of human resources. Most recently, he was executive vice president of Alabama Power, with responsibility for the customer service organization. Martin has also served as executive vice president of external affairs at Alabama Power and has held a number of other executive and management positions at that company.

7. Charles D. McCrary

Executive Vice President
President and CEO, Alabama Power

McCrary, 58, joined the Company as an assistant project planning engineer with Alabama Power in 1973. He assumed his current position in 2001. Previously, McCrary was chief production officer for Southern Company and president and CEO of Southern Power. He has held executive positions at Alabama Power and Southern Nuclear as well as various jobs in engineering, system planning, fuels, and environmental affairs.

8. James H. Miller III

President and CEO, Southern Nuclear

Miller, 60, joined the Company as general counsel for Southern Nuclear in 1994. He assumed his current position in 2008. Previously, Miller served as senior vice president, compliance officer, and general counsel for Georgia Power. He also has held the positions of senior vice president of external affairs and senior vice president of the Birmingham Division at Alabama Power.

C-89

STOCKHOLDER INFORMATION

Transfer Agent

SCS Stockholder Services is Southern Company’s transfer agent, dividend-paying agent, investment plan administrator, and registrar.

If you have questions concerning your Southern Company stockholder account, please contact:

By mail

SCS Stockholder Services

P.O. Box 54250

Atlanta, GA 30308-0250

By phone

9 to 5 ET

Monday through Friday

800-554-7626

By courier

SCS Stockholder Services

30 Ivan Allen Jr. Blvd. NW

11th Floor-Bin SC1100

Atlanta, GA 30308

By e-mail

stockholders@southerncompany.com

Stockholder Services Internet Site

Located within Southern Company’s Investor Relations website at http://investor.southerncompany.com, the Stockholder Services site provides transfer instructions, service request forms, and answers to frequently asked questions. Through this site, registered stockholders may also securely access their account information, including share balance, market value, and dividend payment details, as well as change their account mailing addresses.

Southern Investment Plan

The Southern Investment Plan provides a convenient way to purchase common stock and reinvest dividends. You can access the Stockholder Services Internet site to review the Prospectus and download an enrollment form.

Direct Registration

Southern Company common stock can be issued in direct registration (uncertificated) form. The stock is Direct Registration System eligible.

Dividend Payments

The entire amount of dividends paid in 2009 is taxable. The board of directors sets the record and payment dates for quarterly dividends. A dividend of 43.75 cents per share was paid in March 2010. For the remainder of 2010, projected record dates are May 3, August 2, and November 1. Projected payment dates for dividends declared during the remainder of 2010 are June 5, September 4, and December 6.

Auditors

Deloitte & Touche LLP

191 Peachtree St. NE

Suite 1500

Atlanta, GA 30303

During 2009, there were no changes in or disagreements with the auditors on accounting and financial disclosure.

C-91

C/O PROXY SERVICES

P. O. BOX 9112

FARMINGDALE, NY 11735

If you vote by Internet or Phone, please do not mail this form.

VOTE BY INTERNET - www.proxyvote.com

Use the Internet to transmit your voting instructions and for electronic delivery of information up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you access the website and follow the instructions to obtain your records and to create an electronic voting instruction form.

VOTE BY PHONE - 1-800-690-6903

Use any touch-tone telephone to transmit your voting instructions up until 11:59 P.M. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you call and then follow the instructions.

VOTE BY MAIL

Mark, sign and date this form and return it in the postage-paid envelope we have provided or return it to The Southern Company, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.

ELECTRONIC DELIVERY OF FUTURE PROXY MATERIALS

If you would like to reduce the costs incurred by The Southern Company in mailing proxy materials, you can consent to receiving all future proxy statements with annual reports and proxy cards electronically via the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive materials electronically in future years.

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VIEW THE PROXY STATEMENT ON THE INTERNET

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TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:

M23189-P93798

KEEP THIS PORTION FOR YOUR RECORDS

THIS FORM OF PROXY OR TRUSTE E VOTING INSTRUCTION FORM IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY

THE SOUTHERN COMPANY The Board of Directors recommends a vote FOR Items 1, 2, 3, 4, and 5.	For All	Withhold All	For All Except	To withhold authority to vote for any individual nominee(s), mark “For All Except” and write the number(s) of the nominee(s) on the line below
	0	0	0	______________________________________

1. ELECTION OF DIRECTORS Nominees:
01)	J. P. Baranco	07)	D. M. James
02)	J. A. Boscia	08)	J. N. Purcell
03)	H. A. Clark III	09)	D. M. Ratcliffe
04)	H. W. Habermeyer, Jr.	10)	W. G. Smith, Jr.
05)	V. M. Hagen	11)	L. D. Thompson
06)	W. A. Hood, Jr.

		For	Against	Abstain
2.	RATIFICATION OF THE APPOINTMENT OF DELOITTE & TOUCHE LLP AS THE COMPANY’S INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2010	0	0	0
3.	AMENDMENT OF COMPANY’S BY-LAWS REGARDING MAJORITY VOTING AND CUMULATIVE VOTING	0	0	0
4.	AMENDMENT OF COMPANY’S CERTIFICATE OF INCORPORATION REGARDING CUMULATIVE VOTING	0	0	0
5.	AMENDMENT OF COMPANY’S CERTIFICATE OF INCORPORATION TO INCREASE NUMBER OF AUTHORIZED SHARES OF COMMON STOCK	0	0	0
The Board of Directors recommends a vote AGAINST Items 6 and 7.
6.	STOCKHOLDER PROPOSAL ON CLIMATE CHANGE ENVIRONMENTAL REPORT	0	0	0
7.	STOCKHOLDER PROPOSAL ON COAL COMBUSTION BYPRODUCTS ENVIRONMENTAL REPORT	0	0	0

UNLESS OTHERWISE SPECIFIED ABOVE, THE SHARES WILL BE VOTED "FOR" ITEMS 1, 2, 3, 4, and 5 and "AGAINST" ITEMS 6 and 7.

NOTE: The last instruction received either paper or electronic prior to the deadline will be the instruction included in the final tabulation.


Signature [PLEASE SIGN WITHIN BOX]	Date			Signature (Joint Owners)	Date

Admission Ticket

(Not Transferable)

2010 Annual Meeting of Stockholders 10 A.M. ET, May 26, 2010
The Lodge Conference Center at Callaway Gardens Highway 18 Pine Mountain, GA 31822
Please present this Admission Ticket in order to gain admittance to the meeting.	Ticket admits only the stockholder(s) listed on reverse side and is not transferable.

Directions to Meeting Site:

From Atlanta, GA - Take I-85 south to I-185 (Exit 21), then Exit 34, Georgia Highway 18. Take Georgia Highway 18 east

to Callaway.

From Birmingham, AL - Take U.S. Highway 280 east to Opelika, AL, then I-85 north to Georgia Highway 18 (Exit 2). Take Georgia Highway 18 east to Callaway.

Important Notice Regarding Internet Availability of Proxy Materials for the Annual Meeting:

The Notice and Proxy Statement with Annual Report are available at www.proxyvote.com.

		M23190-P93798
FORM OF PROXY AND TRUSTEE VOTING INSTRUCTION FORM		FORM OF PROXY AND TRUSTEE VOTING INSTRUCTION FORM

PROXY SOLICITED ON BEHALF OF BOARD OF DIRECTORS AND ESP TRUSTEE

If a stockholder of record, the undersigned hereby appoints D. M. Ratcliffe, W. P. Bowers and G. E. Holland, Jr., or any of them, Proxies, with full power of substitution in each, to vote all shares the undersigned is entitled to vote at the Annual Meeting of Stockholders of The Southern Company, to be held at The Lodge Conference Center at Callaway Gardens in Pine Mountain, Georgia, on May 26, 2010, at 10:00 a.m., ET, and any adjournments thereof, on all matters properly coming before the meeting, including, without limitation, the items listed on the reverse side of this form.

If a beneficial owner holding shares through the Employee Savings Plan (ESP), the undersigned directs the Trustee of the Plan to vote all shares the undersigned is entitled to vote at the Annual Meeting of Stockholders, and any adjournments thereof, on all matters properly coming before the meeting, including, without limitation, the items listed on the reverse side of this form.

This Form of Proxy/Trustee Voting Instruction Form is solicited jointly by the Board of Directors of The Southern Company and the Trustee of the ESP pursuant to a separate Notice of Annual Meeting and Proxy Statement. If not voted electronically, this form should be mailed in the enclosed envelope to the Company's proxy tabulator at 51 Mercedes Way, Edgewood, NY 11717. The deadline for receipt of Trustee Voting Instruction Forms for the ESP is 5:00 p.m. on Monday, May 24, 2010. The deadline for receipt of shares of record voted through the Form of Proxy is 9:00 a.m. on Wednesday, May 26, 2010. The deadline for receipt of instructions provided electronically is 11:59 p.m. on Tuesday, May 25, 2010.

The proxy tabulator will report separately to the Proxies named above and to the Trustee as to proxies received and voting instructions provided, respectively.

THIS FORM OF PROXY/TRUSTEE VOTING INSTRUCTION FORM WILL BE VOTED AS SPECIFIED

BY THE UNDERSIGNED. IF NO CHOICE IS INDICATED, THE SHARES WILL BE VOTED AS THE

BOARD OF DIRECTORS RECOMMENDS.

Continued and to be voted and signed on reverse side.

*** IMPORTANT MESSAGE ABOUT VOTING YOUR SHARES ***

Recently, NYSE and SEC rule changes were enacted changing how shares held in brokerage accounts are voted in director elections. If YOU do not vote your shares on proposal one (Election of Directors), your brokerage firm can no longer vote them for you; your shares will remain unvoted. Previously, if your broker did not receive instructions from you, they were permitted to vote your shares for you in director elections. However, starting January 1, 2010, under changes to NYSE Rule 452, brokers will no longer be allowed to vote uninstructed shares.

Therefore, it is very important that you vote your shares for all proposals including the election of directors.

In addition to checking the appropriate boxes on the enclosed vote instruction form, signing and returning it in the enclosed postage paid envelope, there are two additional convenient ways to vote that are available 24 hours a day:

Vote by Internet	Vote by Telephone
Go to website: www.proxyvote.com	Call toll-free on a touch-tone phone in the U.S. or Canada
Follow these four easy steps:	Follow these four easy steps:
 Read the accompanying Proxy materials.	 Read the accompanying Proxy materials.
 Go to website www.proxyvote.com.	 Call the toll-free phone number printed on the enclosed vote instruction form.
 Have your vote instruction form in hand when you access the website.	 Have your vote instruction form in hand when you call the toll-free number.
 Follow the simple instructions.	 Follow the recorded instructions: * Press 1 to vote as the Board recommends * Press 2 to vote each proposal individually
******* Note ********
When voting online, you may also elect to give your consent to have all future proxy materials delivered to you electronically.
Do not return your vote instruction form if you are voting by Internet or Telephone



VOTE BY INTERNET			VOTE BY PHONE

www.proxyvote.com			1-800-690-6903

24 hours a day/7 days a week			Toll-free 24 hours a day/7 days a week



Instructions:			Instructions:

n Read this Proxy Statement			n Read this Proxy Statement

n Go to the following website: www.proxyvote.com



Have your proxy form or voting instruction form in hand and follow the instructions.			Have your proxy form or voting instruction form in hand and follow the instructions.


		Compensation and Management Succession Committee (Compensation Committee):

n		Members are Mr. Purcell (Chair), Mr. Clark (1), Mr. Habermeyer, and Mr. James

n		Met eight times in 2009

n		Evaluates performance of executive officers and establishes their compensation, administers executive compensation plans, and reviews management succession plans. Annually reviews a tally sheet of all components of the executive officers’ compensation and takes actions required of it under the Pension Plan for employees of the Company.


Engagement by the Compensation Committee (executive compensation consulting)	$	582,876
Health and Welfare Plan Projects	$	560,959
Development of communications for compensation program changes	$	118,544


Name and Address	Shares Beneficially Owned		Percentage of Class Owned

Blackrock, Inc. 40 East 52^nd Street New York, NY 10022		41,952,022		5.24	%



		Jon A. Boscia Age: Director since: Board committee: Principal occupation: Director qualifications:		57 2007 Audit President of Sun Life Financial Inc., financial services In September 2008, Mr. Boscia assumed the role of President of Sun Life Financial Inc. In this capacity, Mr. Boscia manages a portfolio of the company’s operations, including the Sun Life Financial U.S. business group, the investments function, worldwide marketing and communications, the Bermuda operation which markets products internationally, and other strategic international initiatives. Previously, Mr. Boscia served as Chairman of the Board and Chief Executive Officer of Lincoln Financial Group, a diversified financial services organization, until his retirement in 2007. Mr. Boscia became the Chief Executive Officer of Lincoln Financial Group in 1998. During his time at Lincoln Financial Group, the company earned a reputation for its stellar performance in making major acquisitions. Mr. Boscia is a past member of the board of The Hershey Company where he chaired the Corporate Governance Committee and served on the Executive Committee. In addition, Mr. Boscia has served in leadership positions on other public company boards as well as not-for-profit and industry boards. His extensive background in finance, investment management, and information technology are valuable to the Board.

		Other directorships:		Armstrong World Industries (formerly a Director of Lincoln Financial Group and The Hershey Company)

Filed by the Registrant S
Filed by a Party other than the Registrant £


Letter to Stockholders

Notice of Annual Meeting of Stockholders — May 26, 2010

Voting Information

Proxy Statement			1

Frequently Asked Questions			1

Corporate Governance			3

Company Organization			3

Corporate Governance Website			3

Director Independence			3

Communicating with the Board			4

Director Compensation			5

Director Deferred Compensation Plan			5

Director Compensation Table			6

Director Stock Ownership Guidelines			6

Board Leadership Structure			6

Presiding Director			7

Meetings of Non-Management Directors			7

Committees of the Board			7

Committee Charters			7

Audit			7

Compensation and Management Succession			8

Finance			9

Governance			9

Nominees for Election to the Board			9

Nuclear/Operations			10

Board Risk Oversight			10

Director Attendance			10

Stock Ownership Table			11

Matters to be Voted Upon			13

Item No. 1 — Election of Directors			13

Item No. 2 — Ratification of Appointment of Independent Registered Public Accounting Firm			22

Item No. 3 — Amendment of By-Laws for Adoption of a Majority Vote Standard			23

Item No. 4 — Amendment of Certificate of Incorporation to Eliminate Cumulative Voting Conditioned upon Adoption of a Majority Vote Standard			24

Item No. 5 — Amendment of Certificate of Incorporation to Increase the Number of Authorized Shares of Common Stock			25

Item No. 6 — Stockholder Proposal on Climate Change Environmental Report			26

Item No. 7 — Stockholder Proposal on Coal Combustion Byproducts Environmental Report			28

Audit Committee Report			30

Executive Compensation			32

Compensation Discussion and Analysis			32

Compensation and Management Succession Committee Report			47

Summary Compensation Table			47

Grants of Plan-Based Awards in 2009			51

Outstanding Equity Awards at 2009 Fiscal Year-End			53

Option Exercises and Stock Vested in 2009			54

Pension Benefits at 2009 Fiscal Year-End			54

Nonqualified Deferred Compensation as of 2009 Fiscal Year-End			56

Potential Payments upon Termination or Change in Control			58

Compensation Program Risk			64

Other Information			64

Section 16(a) Beneficial Ownership Reporting Compliance			64

Certain Relationships and Related Transactions			64

Appendix A — Proposed Amendment to the Company’s By-Laws

Appendix B — Policy on Engagement of the Independent Auditor For Audit and Non-Audit Services

Appendix C — 2009 Annual Report


•	Considering compensation for the named executive officers in the context of all of the components of total compensation.

•	Considering annual adjustments to pay over the course of two meetings and requiring more than one meeting to make other important decisions.

•	Receiving meeting materials several days in advance of meetings.

•	Having regular executive sessions of Compensation Committee members only.

•	Having direct access to outside compensation consultants.

•	Conducting a performance/payout analysis versus peer companies for the performance-based compensation program to provide a check on the Company’s goal-setting process.

•	Reviewing a compensation risk assessment process developed by its outside compensation consultant.



		Henry A. “Hal” Clark III Age: Director since: Board committees: Principal occupation: Director qualifications: Other directorships:		60 2009 Finance (Chair), Compensation and Management Succession Senior Advisor of Lexicon Partners, LLC, corporate finance advisory firm, since July 2009 As a Senior Advisor with Lexicon Partners, LLC, Mr. Clark is primarily focused on expanding advisory activities in North America with a particular focus on the power and utilities sectors. With more than 30 years of experience in the global financial and the utility industries, Mr. Clark brings a wealth of experience in finance and risk management to his role as a Director. Prior to joining Lexicon Partners, Mr. Clark was Group Chairman of Global Power and Utilities at Citigroup from 2001-2009. His work experience includes numerous capital markets transactions of debt, equity, bank loans, convertibles, and securitization, as well as advice in connection with mergers and acquisitions. He also has served as policy advisor to numerous clients on capital structure, cost of capital, dividend strategies, and various financing strategies. He has served as Chair of the Wall Street Advisory Group of the Edison Electric Institute. None



		H. William Habermeyer, Jr. Age: Director since: Board committees: Director qualifications: Other directorships:		67 2007 Nuclear/Operations (Chair), Compensation and Management Succession Mr. Habermeyer retired in 2006 from his position as President and Chief Executive Officer of Progress Energy Florida, Inc., a subsidiary of Progress Energy Inc., a diversified energy company. Mr. Habermeyer has a wealth of experience in utility business operations, with a focus on nuclear matters. He joined Progress Energy’s predecessor Carolina Power & Light in 1993 and served in various leadership roles including Vice President of Nuclear Services and Environmental Support, Vice President of Nuclear Engineering, and Vice President of Progress Energy’s Western Region. While overseeing the Western Region operations, Mr. Habermeyer was responsible for regional distribution management, customer support, and community relations. He currently serves on the Compensation, and Technology and Competition Committees of the board of USEC Inc., a global energy company, and the Audit Committee of Raymond James Financial Inc. Mr. Habermeyer is a retired Rear Admiral who served in the United States Navy for 28 years. His military medals include seven awards of the Legions of Merit, two Navy Commendation Medals, and service and campaign awards. Raymond James Financial Inc., USEC Inc.



		Veronica M. “Ronee” Hagen Age: Director since: Board committees: Principal occupation: Director qualifications: Other directorships:		64 2008 Governance, Nuclear/Operations Chief Executive Officer of Polymer Group, Inc., engineered materials, since April 2007 Ms. Hagen’s global operational management experience and commercial business leadership are valuable assets to Southern Company’s Board. Polymer Group is a public company which is the leading producer and marketer of engineered materials. Prior to joining Polymer Group, Ms. Hagen was the President and Chief Executive Officer of Sappi Fine Paper, a division of Sappi Limited, the South African-based global leader in the pulp and paper industry, from November 2004 until her resignation in 2007. She also has served as Vice President and Chief Customer Officer at Alcoa and owned and operated Metal Sales Associates, a privately-held metal business. Ms. Hagen also serves on the Operations and Safety and Environmental and Social Responsibility Committees of the board of Newmont Mining Corporation. Polymer Group, Inc., Newmont Mining Corporation



		Warren A. Hood, Jr. Age: Director since: Board committee: Principal occupation: Director qualifications: Other directorships:		58 2007 Audit Chairman of the Board and Chief Executive Officer of Hood Companies Incorporated, packaging and construction products Mr. Hood is the Chief Executive Officer of Hood Companies Incorporated which includes four separate corporations with 60 manufacturing and distribution sites throughout the United States, Canada, and Mexico. Mr. Hood previously served on the board of the Company’s subsidiary, Mississippi Power, where he was also a member of the Compensation Committee. Mr. Hood has long been recognized for his leadership role in the State of Mississippi. He serves on numerous corporate, community, and philanthropic boards, including BancorpSouth Bank, Boy Scouts of America, and The Governor’s Commission on Rebuilding, Recovery and Renewal, which was formed following Hurricane Katrina in 2005. Mr. Hood’s business operations, risk management, and financial experience and civic involvement are valuable to the Board. Hood Companies Incorporated, BancorpSouth Bank (formerly a Director of Mississippi Power)



		Donald M. James Age: Director since: Board committees: Principal occupation: Director qualifications: Other directorships:		61 1999, Presiding Director since January 1, 2010 Compensation and Management Succession, Finance Chairman of the Board and Chief Executive Officer of Vulcan Materials Company, construction materials Mr. James joined Vulcan Materials in 1992 as Senior Vice President and General Counsel and then became President of the Southern Division and then Senior Vice President of the Construction Materials Group and President of the Southern Division. Prior to joining Vulcan Materials, Mr. James was a partner at the law firm of Bradley, Arant, Rose & White for 10 years. Mr. James is also a Director of the UAB Health System, Boy Scouts of Central Alabama, and the Economic Development Partnership of Alabama, Inc. In addition, he serves on the Finance and Human Resources Committees of Wells Fargo & Company’s Board of Directors. Mr. James’ leadership of a large, public company, his legal expertise, and his civic involvement are valuable assets to the Board. Vulcan Materials Company, Wells Fargo & Company (formerly a Director of Protective Life Corporation)



		William G. Smith, Jr. Age: Director since: Board committee: Principal occupation: Director qualifications: Other directorships:		56 2006 Audit (Chair) Chairman of the Board, President, and Chief Executive Officer of Capital City Bank Group, Inc., banking Mr. Smith began his career at Capital City Bank in 1978, where he worked in a number of capacities before being elected President and Chief Executive Officer of Capital City Bank Group in January 1989. He was then elected Chairman of the Board of the Capital City Bank Group Inc., a public company, in 2003. He has also served on the Board of Directors of the Federal Reserve Bank of Atlanta. Mr. Smith serves on the Board of Trustees for Darlington School in Rome, Georgia, and the Florida State University Foundation. He is the former Federal Advisory Council Representative for the Sixth District of the Federal Reserve System and past Chair of both Tallahassee Memorial HealthCare and the Tallahassee Area Chamber of Commerce. Mr. Smith’s experience in finance, business operations, and risk management is valuable to the Board. In addition, Mr. Smith qualifies as an audit committee financial expert. Capital City Bank Group, Inc., Capital City Bank


	2009		2008

	(In thousands)

Audit Fees(a)	$	11,368	$	12,439
Audit-Related Fees(b)		546		900
Tax Fees		0		0
All Other Fees		0		0

Total	$	11,914	$	13,339


(a)		Includes services performed in connection with financing transactions.

(b)		Includes benefit plan and other non-statutory audit services and accounting consultations in both 2009 and 2008.



Southern Company Common Stock and Dividend Information			ii


Five-Year Cumulative Performance Graph			ii


Ten-Year Cumulative Performance Graph			iii


Management’s Report on Internal Control over Financial Reporting			C-1


Report of Independent Registered Public Accounting Firm			C-2


Management’s Discussion and Analysis of Financial Condition and Results of Operations			C-3


Quantitative and Qualitative Disclosures about Market Risk			C-27


Cautionary Statement Regarding Forward-Looking Statements			C-31


Consolidated Statements of Income			C-32


Consolidated Statements of Cash Flows			C-33


Consolidated Balance Sheets			C-34


Consolidated Statements of Capitalization			C-36


Consolidated Statements of Common Stockholders’ Equity			C-38


Consolidated Statements of Comprehensive Income			C-39


Notes to Financial Statements			C-40


Selected Consolidated Financial and Operating Data			C-87


Management Council			C-89


Stockholder Information			C-91


	High		Low		Dividend


2009
First Quarter	$	37.62	$	26.48	$	0.4200
Second Quarter		32.05		27.19		0.4375
Third Quarter		32.67		30.27		0.4375
Fourth Quarter		34.47		30.89		0.4375
2008
First Quarter	$	40.60	$	33.71	$	0.4025
Second Quarter		37.81		34.28		0.4200
Third Quarter		40.00		34.46		0.4200
Fourth Quarter		38.18		29.82		0.4200


					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 MC Asset Recovery litigation settlement reduced earnings by $202 million, or 25 cents per share, during the first quarter of 2009.