Edgar Filing: SOUTHERN CO

SOUTHERN COMPANY

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(A) of the

Securities Exchange Act Of 1934

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THE SOUTHERN COMPANY

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Notice of

Annual Meeting

2009

& Proxy Statement

PROXY STATEMENT

Contents


Letter to Stockholders

Notice of Annual Meeting of Stockholders — May 27, 2009

Proxy Statement			1

General Information			1

Mailing Date			1

Giving Voting Instructions			1

Revocation of Proxies			1

Electronic Delivery of Proxy Materials			1

Householding Information			1

Stockholder Proposals for the 2010 Proxy Materials			2

Cost of Proxy Solicitation			2

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

Meetings of Non-Employee Directors			6

Committees of the Board			7

Committee Charters			7

Audit			7

Compensation and Management Succession			7

Finance			8

Governance			8

Nominees for Election to the Board			9

Nuclear/Operations			9

Director Attendance			9

Stock Ownership Table			10

Matters to be Voted Upon			11

Item No. 1 — Election of Directors			11

Item No. 2 — Ratification of Appointment of Independent Registered Public Accounting Firm			15

Item No. 3 — Amendment of By-Laws			15

Item No. 4 — Amendment of Certificate of Incorporation			17

Item No. 5 — Stockholder Proposal on Environmental Report			17

Item No. 6 — Stockholder Proposal on Pension Policy			19

Audit Committee Report			21

Executive Compensation			23

Compensation Discussion and Analysis			23

Compensation and Management Succession Committee Report			37

Summary Compensation Table			37

Grants of Plan-Based Awards Table			41

Outstanding Equity Awards Table			43

Option Exercises and Stock Vested Table			44

Pension Benefits Table			44

Nonqualified Deferred Compensation Table			47

Potential Payments upon Termination or Change in Control			48

Other Information			55

Section 16(a) Beneficial Ownership Reporting Compliance			55

Certain Relationships and Related Transactions			55

Appendix A — Proposed Amendment of By-Laws

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

Appendix C — 2008 Annual Report

Letter to Stockholders



David M. Ratcliffe Chairman, President and Chief Executive Officer



Dear Fellow Stockholder:

You are invited to attend the 2009 Annual Meeting of Stockholders at 10:00 a.m., ET, on Wednesday, May 27, 2009 at The Lodge Conference Center at Callaway Gardens, Pine Mountain, Georgia. At the meeting, I will report on our business and our plans for the future. Also, we will elect our Board of Directors and vote on the other matters set forth in the accompanying Notice. Your vote is important. Please review the proxy material and vote your proxy as soon as possible. In other matters, you will notice that your proxy package does not include the 2008 Southern Company Annual Report this year. Your proxy statement contains most of the financial information you normally receive. However, because of the economic and financial challenges affecting us all, we made the decision to eliminate the expense of printing thousands of annual reports. This decision not only reduces our costs, but also adds environmental benefits. Our 2008 Summary Annual Report is posted on our website, www. southerncompany.com, and we invite you to read it there. As always, we are managing the costs in our business to ensure reliable service at competitive prices for our customers, while achieving greater efficiency. We are also continuing to invest capital where it’s needed.

We remain focused on our proven business strategy of making conservative, informed, and balanced decisions based on common sense. Thank you for your confidence in our company. We look forward to seeing you May 27. David M. Ratcliffe

Notice of Annual Meeting of Stockholders — May 27, 2009

TIME AND DATE

10:00 a.m., ET, on Wednesday, May 27, 2009

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 12 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;

(4) Consider and vote on an amendment to the Company’s Certificate of Incorporation;


(5)	Consider and vote on the stockholder proposals if presented at the meeting as described in Item Nos. 5 and 6 of the Proxy Statement; and

(6) 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, 2009 are entitled to attend and vote at the meeting.

ANNUAL REPORT TO STOCKHOLDERS

Appendix C to this Proxy Statement is Southern Company’s 2008 Annual Report.

VOTING

Even if you plan to attend the meeting in person, please provide your voting instructions in one of the following ways as soon as possible:

(1) Internet — use the Internet address on the proxy form

(2) Telephone — use the toll-free number on the proxy form

(3) Mail — mark, sign, and date the proxy form and return it in the enclosed, postage-paid envelope

By Order of the Board of Directors, G. Edison Holland, Jr., Corporate Secretary, April 13, 2009

Proxy Statement

General Information


Q:		When will the Proxy Statement be mailed?

A:		The Proxy Statement will be mailed on or about April 13, 2009.

Q:		How do I give voting instructions?

A:		You may attend the meeting and give instructions in person or 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:		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, 2009. On that date, there were 782,865,285 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 No. 4.

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 these documents.

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 2008 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 2008 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 2008 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. As noted earlier, beneficial owners may view the Proxy Statement on the Internet.

Q:		When are stockholder proposals due for the 2010 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 2010 Annual Meeting of Stockholders is December 10, 2009. 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 28, 2010.

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 2008 Annual Report to the Securities and Exchange Commission (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 27, 2009:

This Proxy Statement, which includes the 2008 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.

The nominees for election as Directors consist of eleven 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, 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, shareowner, 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 serve 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. Messrs. Francis S. Blake and Donald M. James are the chief executive officers of The Home Depot, Inc. and Vulcan Materials Company, respectively. Throughout 2008, subsidiaries of the Company purchased goods and services in the amount of approximately $706,000 from The Home Depot, Inc. and approximately $1,668,000 from Vulcan Materials Company. These amounts represented numerous individual purchases from The Home Depot, Inc. and several individual transactions with Vulcan Materials Company. 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 Director of the Company, is a senior vice president of government relations and advocacy, and general counsel for Habitat for Humanity International. In 2008, the Company, primarily through its foundation and the foundations of its subsidiaries, supported Habitat for Humanity International through charitable contributions of approximately $348,000. 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, Francis S. Blake, Jon A. Boscia, Thomas F. Chapman, H. William Habermeyer, Jr., Veronica M. Hagen, Warren A. Hood, Jr., Donald M. James, J. Neal Purcell, William G. Smith, Jr., and Gerald J. St. Pé. Also, Dorrit J. Bern, who served as a Director during 2008 until her resignation date of July 21, 2008, 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 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.

Effective January 1, 2008, the director compensation program was amended with pay components being as follows:


		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 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 2008, 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		101,916		90,000		—		—		—		790		192,706

Dorrit J. Bern(4)		58,168		52,500		—		—		—		—		110,668

Francis S. Blake		91,500		90,000		—		—		—		—		181,500

Jon A. Boscia		94,833		92,500		—		—		—		—		187,333

Thomas F. Chapman		105,042		90,000		—		—		—		—		195,042

H. William Habermeyer, Jr.		104,000		90,000		—		—		—		—		194,000

Veronica M. Hagen(5)		—		—		—		—		—		—		—

Warren A. Hood, Jr.		94,833		92,500		—		—		—		—		187,333

Donald M. James		101,916		90,000		—		—		—		461		192,377

J. Neal Purcell		104,000		90,000		—		—		—		—		194,000

William G. Smith, Jr.		101,916		90,000		—		—		—		2,418		194,334

Gerald J. St. Pé		89,584		90,000		—		—		—		6,692		186,276


(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)		Ms. Bern resigned as a Director of the Company on July 21, 2008.
(5)		Ms. Hagen became a Director of the Company on December 8, 2008.

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.

MEETINGS OF NON-EMPLOYEE DIRECTORS

Non-employee Directors meet in executive session with no member of management present on each regularly-scheduled Board meeting date. There is a Presiding Director at each of these executive sessions. Mr. Thomas F. Chapman became the Presiding Director on May 23, 2007 and will serve until December 31, 2009 or until a successor is named by the non-employee Directors.

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. Blake, and Mr. Hood (1)

n		Met nine times in 2008

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. Smith was appointed Chair and Ms. Bern and Mr. Hood were appointed as members of the Audit Committee on January 21, 2008. On July 21, 2008, Ms. Bern resigned from the Board.


		Compensation and Management Succession Committee (Compensation Committee):

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

n		Met seven times in 2008

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.

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

(1) Mr. Purcell was appointed Chair and Messrs. Boscia and Habermeyer were appointed as members of the Compensation Committee on January 21, 2008.


		Governance

During 2007 and 2008, the Compensation Committee’s governance practices included:


•	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 annual incentive program to provide a check on the Company’s goal-setting process.

Role of Executive Officers

The Chief Executive Officer, with input from the Human Resources staff, recommends to the Compensation Committee base salary, target bonus levels, actual bonus payouts, and long-term incentive grants for the Company’s executive officers (other than the Chief Executive Officer). The Compensation Committee considers, discusses, modifies as appropriate, and takes action on such proposals.

Role of Compensation Consultant

In 2008, the Compensation Committee directly retained Towers Perrin as its outside compensation consultant. The Compensation Committee informed Towers Perrin in writing that the Compensation Committee expected Towers Perrin to provide an independent assessment of the current executive compensation program and any management-recommended changes to that program and to work with Company management to ensure that the executive compensation program is designed and administered consistent with the Compensation Committee’s requirements. The Compensation Committee also expected Towers Perrin to recommend changes to the executive and related corporate governance trends.

During 2008, Towers Perrin assisted the Compensation Committee with comprehensive market data and its implications for pay at the Company and various other governance, design, and compliance matters.

Compensation Committee Interlocks and Insider Participation

None of the persons who served as members of the Compensation Committee during 2008 was an officer or employee of the Company during 2008 or at any time in the past nor had reportable transactions with the Company.


		Finance Committee:

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

n		Met eight times in 2008

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. James was appointed Chair and Messrs. Boscia and Purcell were appointed members of the Finance Committee on January 21, 2008. Ms. Bern served as Chair of the Finance Committee until January 21, 2008.


		Governance Committee:

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

n		Met seven times in 2008

n		Oversees the composition of the Board and its committees, determines non-employee 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. Baranco was appointed a member and Chair of the Governance Committee on January 21, 2008. Mr. Chapman served as Chair of the Governance Committee until January 21, 2008. Ms. Hagen was appointed to the Governance Committee on 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 10, 2009 for consideration by the Governance Committee as a nominee for election at the Annual Meeting of Stockholders to be held in 2010. Any stockholder recommendation is reviewed in the same manner as candidates identified by the Governance Committee or recommended to the Governance Committee.

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 be diverse and have collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and the Company’s industry. During 2008, 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 of Directors for consideration as nominees. Final selection of the nominees is within the sole discretion of the Board of Directors.

Ms. Veronica M. Hagen was recommended by the Governance Committee for election to the Board and was elected as a Director effective December 8, 2008. Ms. Hagen was identified jointly by the members of the Governance Committee and the third-party search firm referenced above.


		Nuclear/Operations Committee:(1)

n		Members are Mr. Habermeyer (Chair), Ms. Baranco, Ms. Hagen, and Mr. St. Pé(2)

n		Met eight times in 2008

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) Effective January 21, 2008, the Committee’s name was changed from the Nuclear Committee to the Nuclear/Operations Committee.

(2) Mr. Habermeyer was appointed Chair and Ms. Baranco and Mr. St. Pé were appointed members of the Committee on January 21, 2008. Ms. Hagen was appointed to the Nuclear/Operations Committee on February 16, 2009.

DIRECTOR ATTENDANCE

The Board of Directors met eight times in 2008. The average attendance for Directors at all Board and Committee meetings was 98 percent. No nominee attended less than 75 percent of applicable meetings.

Directors are expected to attend the Annual Meeting of Stockholders. All of the members of the Board of Directors serving on May 28, 2008, the date of the 2008 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, 2008. 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		15,418		14,916

Francis S. Blake		22,671		22,471

Jon A. Boscia		6,616		2,616

W. Paul Bowers		213,714				203,597

Thomas F. Chapman		33,799		33,799

Thomas A. Fanning		372,312				366,405

Michael D. Garrett		268,388				266,372

H. William Habermeyer, Jr.		4,172		4,172

Veronica M. Hagen		0

Warren A. Hood, Jr.		8,482		8,482

Donald M. James		48,214		46,214

Charles D. McCrary		363,802				358,541

J. Neal Purcell		34,643		28,419				224

David M. Ratcliffe		2,127,139				2,109,540

William G. Smith, Jr.		18,369		14,561

Gerald J. St. Pé		101,980		48,059				8,886

Directors, Nominees, and Executive Officers as a Group (20 people)		4,410,171		223,709		4,035,880		9,110


(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.

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 2010 Annual Meeting of Stockholders.



		Juanita Powell Baranco Age: Director since: Board committees: Principal occupation: Other directorships:		60 2006 Governance (chair), Nuclear/Operations Executive vice president and chief operating officer of Baranco Automotive Group, automobile sales Cox Radio, Inc.



		Francis S. Blake Age: Director since: Board committee: Principal occupation: Recent business experience: Other directorships:		59 2004 Audit Chairman of the board and chief executive officer of The Home Depot Inc., home improvement Served as U.S. Deputy Secretary of Energy from May 2001 to April 2002 and as executive vice president of The Home Depot Inc. until January 2007 when he assumed his current position The Home Depot Inc.



		Jon A. Boscia Age: Director since: Board committees: Principal occupation: Recent business experience: Other directorships:		56 2007 Compensation and Management Succession, Finance President of Sun Life Financial Inc., financial services Served as chairman of the board and chief executive officer of Lincoln Financial Group, insurance, institutional investments, comprehensive financial planning and advisory services, until his retirement in 2007. He assumed his current position in September 2008. Armstrong World Industries


		Thomas F. Chapman Age: Director since: Board committee: Principal occupation: Recent business experience: Other directorships:		65 1999, Presiding Director since May 23, 2007 Governance Retired chairman of the board and chief executive officer of Equifax Inc., information services, data analytics, transaction processing, and consumer financial products Served as chairman of the board and chief executive officer of Equifax Inc. until his retirement in 2005 None



		H. William Habermeyer, Jr. Age: Director since: Board committees: Principal occupation: Recent business experience: Other directorships:		66 2007 Nuclear/Operations (chair), Compensation and Management Succession Retired president and chief executive officer of Progress Energy Florida, Inc. energy Served as president and chief executive officer of Progress Energy Florida, Inc. until his retirement in 2006 Raymond James Financial Inc., USEC Inc.



		Veronica M. “Ronee” Hagen Age: Director since: Board committees: Principal occupation: Other directorships:		63 2008 Governance, Nuclear/Operations Chief executive officer of Polymer Group, Inc., engineered materials Polymer Group, Inc., Newmont Mining Corporation


		Warren A. Hood, Jr. Age: Director since: Board committee: Principal occupation: Other directorships:		57 2007 Audit Chairman of the board and chief executive officer of Hood Companies Incorporated, packaging and construction products Hood Companies Incorporated, BancorpSouth Bank


		Donald M. James Age: Director since: Board committees: Principal occupation: Other directorships:		60 1999 Finance (chair), Compensation and Management Succession Chairman of the board and chief executive officer of Vulcan Materials Company, construction materials Vulcan Materials Company, Wells Fargo & Company



		J. Neal Purcell Age: Director since: Board committees: Principal occupation: Recent business experience: Other directorships:		67 2003 Compensation and Management Succession (chair), Finance Retired vice-chairman, audit operations, of KPMG, audit and accounting Served as KPMG’s vice-chairman in charge of National Audit Practice Operations from October 1998 until his retirement in 2002 Kaiser Permanente Health Care and Hospitals, Synovus Financial Corp.


		David M. Ratcliffe Age: Director since: Principal occupation: Recent business experience: Other directorships:		60 2003 Chairman of the board, president and chief executive officer of the Company Served as president and chief executive officer of Georgia Power Company from May 1999 until January 2004 and as chairman and chief executive officer of Georgia Power Company from January 2004 until April 2004. He served as executive vice president of the Company from May 1999 until April 2004, and as president of the Company from April 2004 until July 2004, when he assumed his current position Edison Electric Institute (chair), Nuclear Energy Institute, CSX Corporation, Southern system companies -- Alabama Power Company, Georgia Power Company, and Southern Power Company


		William G. Smith, Jr. Age: Director since: Board committee: Principal occupation: Other directorships:		55 2006 Audit (chair) Chairman of the board, president and chief executive officer of Capital City Bank Group Incorporated, banking Capital City Bank Group, Inc., Capital City Bank



		Gerald J. St. Pé Age: Director since: Board committees: Principal occupation: Recent business experience: Other directorships:		69 1995 Governance, Nuclear/Operations Former president of Ingalls Shipbuilding and retired executive vice president of Litton Industries, shipbuilding Served as chief operating officer of Northrop-Grumman Ship Systems from August 1999 to November 2001 Merchants and Marine Bank, Signal International

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 2009. 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 stockholder 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.


		Amendments

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 CONTESTED 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 or 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 — STOCKHOLDER PROPOSAL ON 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; Benedictine Sisters of Boerne, Texas, 285 Oblate Drive, San Antonio, Texas 78216, holder of 200 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; Congregation of Benedictine Sisters of Perpetual Adoration, Benedictine Monastery, 31970 State Highway P, Clyde, Missouri 64432-8100, holder of 1,050 shares of Common Stock; State of Connecticut Retirement Plans & Trust Funds, 55 Elm Street, Hartford, Connecticut 06106-1773, holder of 317,925 shares of Common Stock; Providence Trust, 515 SW 24th Street, San Antonio, Texas, 78207-4619, holder of 158 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 2009 Annual Meeting of Stockholders.

“Whereas: The International Energy Agency 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 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.

“Carbon dioxide emissions from electric power generation rose by 2.9% in 2007 according to the U.S. Energy Information Administration, the largest single year since 1998.

“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 persist 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 plan 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 greenhouse gas emissions reduction targets. Duke, Exelon, FPL, NRG, and others, through their participation in the U.S. Climate Action Partnership, have also 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 as a way to provide economic and regulatory certainty needed for major investments in our energy future.

“Southern, however, 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, and has reduced the intensity of its CO₂ emissions, it has yet to adopt a voluntary reduction goal for its total CO₂ emissions. (Southern Co. Response to CDP5)

“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, 2009. Such report shall omit proprietary information and be prepared at reasonable cost.”

THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEM NO. 5 FOR THE FOLLOWING REASONS:

In January 2009, the Company signed onto principles developed by members of the Edison Electric Institute that outline a legislative approach to addressing 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. In addition, the Company is updating 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 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 dioxide and other emissions, including an extensive review of carbon dioxide price scenarios; in 2006, its Corporate Responsibility Report, which included 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. All 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. 5.

ITEM NO. 6 — STOCKHOLDER PROPOSAL ON PENSION POLICY

The Company has been advised that the United Brotherhood of Carpenters and Joiners of America, 101 Constitution Avenue, N.W., Washington, D.C. 20001, holder of 12,317 shares of Common Stock, proposes to submit the following resolution at the 2009 Annual Meeting of Stockholders.

“Be It Resolved: That the shareholders of The Southern Company (“Company”) hereby urge that the Board of Director’s Compensation and Management Succession Committee establish an Excess Executive Pension Policy (“Excess Pension Policy”) that limits the retirement benefits to senior executives under the Company’s Supplemental Benefit Plan (Pension-Related) (“SBP-P”) and the Company’s Supplemental Executive Retirement Plan (“SERP”). The Excess Pension Policy should provide that compensation levels used to determine retirement benefits under both supplemental plans be limited to a senior executive’s annual salary, excluding all incentive pay or voluntarily deferred pay from inclusion in the plans’ definition of covered compensation used to establish benefits. The Excess Pension Policy should be implemented in a manner so as not to interfere with existing contractual rights of any participant in either supplemental plan.

“Supporting Statement: We believe that one of the most troubling aspects of the sharp rise in executive compensation is the excessive pension benefits provided to senior corporate executives through the use of supplemental executive retirement plans. The Southern Company has established two supplemental executive retirement plans, the SBP-P and the SERP. These supplemental plans provide the Company’s chief executive officer and other senior executives retirement benefits far greater than those permitted under the Company’s tax-qualified Pension Plan. Our proposal seeks to change these generous supplemental pension benefit plans by limiting the type and amount of compensation that can be used to calculate pension benefits under the plans.

“At present, U.S. tax law maintains a $225,000 limit on the level of compensation used to determine a participant’s retirement benefit under a tax-qualified pension plan. The SBP-P and SERP were established to provide senior executives increased retirement benefits by raising the level of compensation used in the pension formula to calculate retirement benefits. The plans allow the inclusion of an executive’s full base pay in excess of the statutory limit, voluntarily deferred compensation, and incentive or bonus pay to calculate the executive’s full retirement benefit. The Company’s executive compensation disclosure indicates that the senior executives’ salary and annual incentive awards are typically well in excess of the $225,000 compensation limit in the Company’s tax-qualified pension plan.

“Our position is that the inclusion of voluntarily deferred compensation and incentive pay in calculating the level of retirement benefit is overly generous and unjustifiable. The only type of compensation used in the supplemental plans for establishing the level of additional pension benefits should be an executive’s annual salary, minus deferred compensation. No incentive pay or deferred compensation should be included in a senior executive’s pension calculation under the supplemental plans. The inclusion of annual incentive pay in senior executive pension benefit calculations can dramatically increase the pension benefit afforded senior executives and has the additional undesirable effect of converting one-time incentive compensation into guaranteed lifetime pension income. We believe the proposed limitations are necessary and reasonable restrictions on the excessiveness of supplemental retirement benefits.”

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

As described in the Compensation Discussion and Analysis herein, the Company has a comprehensive compensation and benefits program for all employees. In addition to base salary, almost all of the Company’s full-time employees, including members of collective bargaining units, participate in both the incentive compensation program and the retirement program.

The Company’s pay philosophy is that total compensation, including post-employment benefits, should be at the size-adjusted median of the market. This philosophy applies to all employees, including senior executives.

The Compensation Committee is responsible for the oversight and administration of the Company’s executive compensation and benefits program. It has retained an independent compensation consultant that provides advice and counsel on appropriate executive compensation levels based on sound market data. The Company believes that if compensation is deemed appropriate for the senior executive’s job level, benefits, including pension benefits, will be commensurate with that compensation.

Retirement benefits for all employees are based on years of service and final average rate of pay. Averaging pay over the three highest years out of the last 10 years of service mitigates the pension benefit being determined solely because of a single year’s high pay. The proponent’s view is that including voluntary deferred compensation and annual incentive pay in the calculation of final average pay results in “overly generous and unjustifiable” retirement benefits. To the contrary, pension benefits for senior executives are structured to make executive benefits comparable, as a percentage of final average pay, to the benefits provided non-executive employees. Senior executives’ retirement benefits are NOT higher than those of other employees, relative to their rates of pay. The pension plans, both tax-qualified and non-qualified, recognize incentive pay for all employees, not just senior executives. Recognizing voluntary deferred compensation is necessary for providing a consistent level of retirement benefits based on final average rate of pay under our pay-replacement philosophy. In fact, for example, an executive employee who retires from the Company at age 62 with 30 years of service will receive over 15% less in pension benefits, relative to final average pay, than a similarly-situated non-management employee. The Company’s pension program is described in detail in the information following the Pension Benefits Table in this Proxy Statement.

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. 6.

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 2008 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 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 nine meetings during 2008.

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, 2008 and filed with the SEC. The Audit Committee also reappointed Deloitte & Touche as the Company’s independent registered public accounting firm for 2009. Stockholders will be asked to ratify that selection at the Annual Meeting of Stockholders.

Members of the Audit Committee:

William G. Smith, Jr., Chair
Francis S. Blake
Warren A. Hood, Jr.

PRINCIPAL INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FEES

The following represents the fees billed to the Company for the two most recent fiscal years by Deloitte & Touche — the Company’s principal independent registered public accounting firm for 2008 and 2007.


	2008		2007

	(In thousands)

Audit Fees(a)	$	12,439	$	12,525
Audit-Related Fees(b)		900		913
Tax Fees		0		0
All Other Fees		0		0

Total	$	13,339	$	13,438


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

(b)		Includes benefit plan and other non-statutory audit services and accounting consultations in both 2008 and 2007.

The Audit Committee has adopted a Policy on Engagement of the Independent Auditor for Audit and Non-Audit Services (see Appendix B) that includes requirements for the Audit Committee to pre-approve services provided by Deloitte & Touche. This policy was initially adopted in July 2002 and, since that time, all services included in the chart above have been pre-approved by the Audit Committee.

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, and must foster and encourage alignment of executive interests with the interests of our stockholders and our customers. 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 ultimate annual incentive program payouts.

•	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 annual incentive program covers almost all of our nearly 27,000 employees and our change-in-control protection program covers all employees not part of a collective bargaining unit. Our stock options and performance dividends cover approximately 6,300 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 is composed of several components, each of which plays a different role. The table below discusses the intended role of each material pay component, what it rewards, and why we use it. Following the table is additional information that describes how we made 2008 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 Incentive	The Company’s annual incentive program rewards achievement of operational, EPS, and business unit financial goals.	Market practice. Focuses attention on achievement of short-term goals that ultimately works to fulfill our mission to customers and leads to increased stockholder value in the long term.


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


Long-Term Incentive: Stock Options	Stock options reward price increases in the Common Stock over the market price on date of grant, over a 10-year term.	Market practice. Performance-based compensation. Aligns executives’ interests with those of stockholders.

Long-Term Incentive: 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.

Relocation Incentive	Lump sum payment of 10% of base salary provides incentive to geographically relocate.	Enhances the value of the relocation program perquisites.

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 annual incentives or performance dividends 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 incentive 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 in general industry.


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


Perquisites and Other Personal Benefits	Personal financial planning maximizes the perceived value of our executive compensation program to executives and allows them to focus on Company operations. Home security systems lower our risk of harm to executives. Club memberships are provided primarily for business use. Relocation benefits cover the costs associated with geographic relocations at the request of the employer.	Perquisites benefit both the Company and executives, at low cost to the Company.

Post-Termination Pay	Change-in-control agreements provide severance pay, accelerated vesting, and payment of short- and long-term incentive awards upon a change in control of the Company coupled with involuntary termination not for “Cause” or a voluntary termination for “Good Reason.”	Market practice. Providing protections to senior executives upon a change in control minimizes disruption during a pending or anticipated change in control. Payment and vesting occur only upon the occurrence of both an actual change in control and loss of the executive’s position.

MARKET DATA

For the named executive officers, the Compensation Committee reviews compensation data from large, publicly-owned electric and gas utilities. The data was developed and analyzed by Towers Perrin, the compensation consultant retained by the Compensation Committee. The companies included each year in the primary peer group are those whose data is available through the consultant’s database. Those companies are drawn from this list of regulated utilities of $2 billion in revenues and up. Proxy data for the entire list of companies below also is used. No other companies’ data are used in our market-pay comparisons.




AGL Resources Inc.	Energy East Corporation	Pinnacle West Capital Corporation
Allegheny Energy Corporation	Entergy Corporation	PPL Corporation
Alliant Energy Corporation	Exelon Corporation	Progress Energy, Inc.
Ameren Corporation	FirstEnergy Corp.	Public Service Enterprise Group Inc.
American Electric Power Company, Inc.	FPL Group, Inc.	Puget Energy, Inc.
Atmos Energy Corporation	Integrys Energy Company, Inc.	Reliant Energy, Inc.
Calpine Corporation	MDU Resources, Inc.	Salt River Project
CenterPoint Energy, Inc	Mirant Corporation	SCANA Corporation
CMS Energy Corporation	New York Power Authority	Sempra Energy
Consolidated Edison, Inc.	Nicor, Inc.	Sierra Pacific Resources
Constellation Energy Group, Inc.	Northeast Utilities	Southern Union Company
Dominion Resources Inc.	NRG Energy, Inc.	Tennessee Valley Authority
Duke Energy Corporation	NSTAR	The Williams Companies, Inc.
Dynegy Inc.	OGE Energy Corp.	Wisconsin Energy Corporation
Edison International	Pepco Holdings, Inc.	Xcel Energy Inc.
El Paso Corporation	PG&E Corporation

The Company is one of the largest U.S. utility companies based on revenues and market capitalization, and its largest business units are some of the largest in the industry as well. For that reason, the consultant size-adjusts the market data in order to fit it to the scope of our business.

In using this market data, market is defined as the size-adjusted 50th percentile of the data, with a focus on pay opportunities at target performance (rather than actual plan payouts). 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 incentive payout (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 incentives as a percentage of total target compensation opportunities, nor did amounts realized or realizable from prior compensation serve to increase or decrease 2008 compensation amounts. Total target compensation opportunities for senior management as a group are managed to be at the median of the market for companies of our size and in our industry. The total target compensation opportunity established in 2008 for each named executive officer is shown below.


							Total Target
			Annual		Long-Term		Compensation
	Salary		Incentive		Incentive		Opportunity
Name	($)		($)		($)		($)


D. M. Ratcliffe		1,129,467		1,129,467		5,647,338		7,906,272

W. P. Bowers		565,098		423,824		683,763		1,672,685

T. A. Fanning		664,685		498,514		804,269		1,967,468

M. D. Garrett		695,402		521,552		841,432		2,058,386

C. D. McCrary		662,242		496,681		801,306		1,960,229

As is our long-standing practice, the salary levels shown above were not effective until March 2008. Therefore, the amounts reported in the Summary Compensation Table are lower because that table reports actual amounts paid in 2008. For purposes of comparing the value of our compensation program to the market data, stock options are valued at 12%, 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 2008 grant of stock options and the performance dividend targets established for the 2008-2011 performance-measurement period, this value was $8.03 per stock option granted. In the long-term incentive column, 55% of the value shown is attributable to stock options and 45% is attributable to performance dividends. The stock option value used for market data comparisons exceeds the value reported in the Grants of Plan-Based Awards Table because the value above is calculated assuming that the options are held for their full 10-year terms. The calculation of the Black-Scholes value reported in the Grants of Plan-Based Awards Table uses historical holding period averages of approximately five years. The value of stock options, with the associated performance dividends, declined from 2007. In 2007, the value of the dividend equivalents was 10% of the average daily Common Stock price for the year preceding the grant as in 2008, but the value of the stock option was 15% rather than 12%. In 2007, the performance dividends represented 40% of the long-term incentive target value and stock options represented 60% of that value.

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 2008 were below 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 this difference 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. Only the total opportunity for Mr. Bowers was more than 10% under the market data described above, which the Compensation Committee considered appropriate because he was new to the Chief Financial Officer position in 2008.

In 2007, Towers Perrin analyzed the level of actual payouts, for 2006 performance, under the annual incentive 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 2008. That analysis was updated in 2008, for 2007 performance, and those findings were used in establishing goals for 2009.

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.

DESCRIPTION OF KEY COMPENSATION COMPONENTS

2008 Base Salary

Base salaries for each of the named executive officers for 2008 were recommended for the Compensation Committee’s approval by Mr. Ratcliffe, except for his own salary. Those recommendations took the market data into account, as well as the need to retain an experienced team, time in position, and individual performance which included the degree of competence and initiative exhibited and the individual’s relative contribution to the results of operations in prior years. The Compensation Committee approved the recommended salaries in 2008.

Mr. Ratcliffe’s 2008 base salary was set by the Compensation Committee and was influenced by the above-described market data and Mr. Ratcliffe’s performance and time in the position.

2008 Incentive Compensation

Achieving Operational and Financial Goals — Our Guiding Principle for Incentive 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 2008, 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 2008, we also focused on and rewarded:


•	EPS growth;

•	ROE in the top quartile of comparable electric utilities;

•	Dividend growth;

•	Long-term total shareholder return; and

•	Financial integrity — an attractive risk-adjusted return, sound financial policy, and a stable “A” credit rating.

The incentive 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.

2008 Annual Incentive Program

Program Design

The Performance Pay Program is the Company’s annual incentive program. Most employees of the Company are participants, including the named executive officers, for a total of almost 27,000 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 incentive goal structure for 2008 is provided below.


•	Operational goals for 2008 were safety, customer service, 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 Company and Alabama Power Company, 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, including the named executive officers.

•	Business unit financial performance is weighted at 50% of the financial goals. For our traditional utility operating companies (Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company), 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 our other business units, we establish financial performance measures that are tailored to each business unit.

For Messrs. Garrett and McCrary, the annual incentive payout is calculated using the ROE for Georgia Power Company and Alabama Power Company, 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 one-time 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 2008 to eliminate the effect of $83 million in after-tax charges to earnings taken in 2008. The charges related to a position the Company took concerning the timing of tax deductions associated with sale-in-lease-out (SILO) transactions that were challenged by the Internal Revenue Service. In making this decision, the Compensation Committee considered that the charges only affected the timing of deductions taken by the Company related to the SILO transactions, that the future tax benefits due to the timing change are expected to be minimal in future years and will likely have no impact on future Performance Pay Program award sizes, and that the impact of

the tax benefits in earlier years was minimal — an average of just over two percent in 2002 through 2007. This adjustment increased the average payout for 2008 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 Service — 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 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.

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 $4.135 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 the year, 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

Service

Reliability

Availability

Safety

Inclusion

Maximum (1.10)

Top quartile for
each customer
segment

Improve
historical
performance

2.00

0.95

Significant
improvement

Target (1.00)

Top quartile
overall

Maintain
historical
performance

2.75

1.25

Improve

Threshold (0.90)

3rd quartile

Below
historical
performance

3.75

1.50

Below
expectations

0 Trigger

4th quartile

Significant issues

6.00

>1.50

Significant
issues

EPS and Business Unit Financial Performance:

The range of EPS and ROE goals for 2008 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	SILO Tax					Payout		Operational Goal		Goal
Performance	Impacts		ROE			Factor		Achievement		Achievement


Maximum		$2.45		14.25	%		2.00		2.20		0.00

Target		$2.32		13.25	%		1.00		1.00		0.00

Threshold		$2.24		11.00	%		0.50		0.45		0.00

Below threshold		<$2.24		<11.00	%		0.00		0.00		0.00

2008 Achievement

Each named executive officer had a target annual incentive opportunity set by the Compensation Committee at the beginning of 2008. 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 2008 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 2008 goal achievement is shown in the following table. The EPS result shown in the table is adjusted for the SILO after-tax charges taken in 2008 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 2008 Annual Report attached as Appendix C to this Proxy Statement (Financial Statements). EPS, as determined in accordance with generally accepted accounting principles and as reported in the Financial Statements, was $2.26 per share.


								Business Unit
	Operational		EPS,		EPS Goal			Financial		Total Weighted		Total
	Goal		excluding		Performance			Performance		Financial		Payout
	Multiplier		SILO Tax		Factor		Business Unit	Factor		Performance		Factor
Name	(A)		Impacts		(50 % Weight)		Financial Performance	(50% Weight)		Factor (B)		(A x B)

D. M. Ratcliffe		1.07	$	2.37		1.54	Corporate-wide weighted average		1.24		1.39		1.49

W. P. Bowers		1.07	$	2.37		1.54	Corporate-wide weighted average		1.24		1.39		1.49

T. A. Fanning		1.07	$	2.37		1.54	Corporate-wide weighted average		1.24		1.39		1.49

M. D. Garrett		1.08	$	2.37		1.54	13.56% ROE		1.31		1.42		1.54

C. D. McCrary		1.07	$	2.37		1.54	13.30% ROE		1.05		1.29		1.39

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 an annual incentive payout amount, the target opportunity (annual incentive target times base salary) is multiplied by the Total Payout Factor.

Actual performance, as adjusted, exceeded the target performance levels established by the Compensation Committee in early 2008; therefore, the payout levels also exceeded 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 2008 for the annual incentive payout at target-level performance and the actual payout based on the actual performance shown above.


	Target Annual		Actual Annual
Name	Incentive Opportunity ($)		Incentive Payout ($)


D. M. Ratcliffe		1,129,467		1,682,906

W. P. Bowers		423,824		632,073

T. A. Fanning		498,514		742,786

M. D. Garrett		521,552		803,190

C. D. McCrary		496,681		690,387

Stock Options

Stock options are granted annually and were granted in 2008 to the named executive officers and about 6,300 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.

Stock option award sizes for 2008 were calculated using guidelines set by the Compensation Committee as a percentage of base salary as shown in the table below. The number of options granted is the guideline amount divided by the average daily Common Stock price for the 12 months preceding the grant. The guideline percentage was set by the Compensation Committee to deliver target long-term incentive compensation assuming a stock option value, with associated performance dividends, of approximately 25% of that average Common Stock price. As discussed in the Market Data section in this CD&A, in 2008 the target value of the stock options, with the associated performance dividends, was only 22% of that average. Therefore, while the guideline as a percentage of salary was not increased for 2008 stock option awards, the target value of long-term incentive compensation was less in 2008 than in 2007 — $8.03 per share in 2008 and $8.515 per share in 2007.

The calculation of the 2008 stock option grants for the named executive officers is shown below.


					Guideline		Average Daily		Number of Stock
Name	Guideline %		Salary		Amount		Stock Price		Options Granted


D. M. Ratcliffe		2,273% of Salary	$	1,129,467	$	25,672,785	$	36.50		703,280

W. P. Bowers		550% of Salary	$	565,098	$	3,108,039	$	36.50		85,151

T. A. Fanning		550% of Salary	$	664,685	$	3,655,768	$	36.50		100,158

M. D. Garrett		550% of Salary	$	695,402	$	3,824,711	$	36.50		104,786

C. D. McCrary		550% of Salary	$	662,242	$	3,642,331	$	36.50		99,789

For Mr. Ratcliffe, based on the market data, long-term incentive compensation pay opportunity was re-determined in 2008 and therefore the guideline, which as described above is a percentage of salary, was increased accordingly. In 2007, the guideline percentage was 1,703%. 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.

2008 Payout

The peer group used to determine the 2008 payout for the 2005-2008 performance-measurement period consisted of utilities with revenues of $2 billion or more with regulated revenues of 70% or more. Those companies are listed below.



Allegheny Energy, Inc.	Exelon Corporation	Progress Energy, Inc.
Alliant Energy Corporation	FirstEnergy Corporation	Public Service Enterprise Group Inc.
Ameren Corporation	FPL Group, Inc.	Puget Energy, Inc.
American Electric Power Company, Inc.	NiSource Inc.	SCANA Corporation
Consolidated Edison, Inc.	NSTAR	Sempra Energy
DTE Energy Company	OGE Energy Corp.	Sierra Pacific Resources
Energy East Corporation	Pepco Holdings, Inc.	Wisconsin Energy Corporation
Entergy Corporation	Pinnacle West Capital Corp.	Xcel Energy Inc.

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, 2008, based on the 2005-2008 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	%

The above payout scale, when established in 2005, paid 25% of the dividend at the 30th percentile and zero below that. The scale was extended to the 10th percentile on a straight-line basis by the Compensation Committee in October 2005 in order to avoid the earnings volatility and employee relations issues that the payout cliff created.

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 2008, was the 61^st, 48^th, 91^st and 91^st percentile, respectively, resulting in a total payout of 78% of the full year’s Common Stock dividend, or $1.30. This amount was multiplied by each named executive officer’s outstanding stock options at December 31, 2008 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.

2011 Opportunity

The peer group for the 2008-2011 performance-measurement period (which will be used to determine the 2011 payout amount) consists of utility companies with revenues of $1.2 billion or more with regulated revenues of approximately 60% or more. Those companies are listed below.

The guideline used to establish the peer group for the 2005-2008 performance-measurement period was somewhat different from that used in 2008 to establish the peer group for the 2008-2011 performance-measurement period. The guideline for inclusion in the peer group is reevaluated annually as needed to assist in identifying an appropriate number of companies similar to the Company. While the guideline does vary somewhat, 20 of the 24 companies in the peer group for the 2005-2008 performance-measurement period also are in the peer group established for the 2008-2011 performance-measurement period.



Allegheny Energy, Inc.	Edison International	Progress Energy, Inc.
Alliant Energy Corporation	Energy East Corporation	Public Service Enterprise Group Inc.
Ameren Corporation	Entergy Corporation	Puget Energy, Inc.
American Electric Power Company, Inc.	Exelon Corporation	SCANA Corporation
Aquila, Inc.	FPL Group, Inc.	Sierra Pacific Resources
Avista Corporation	Hawaiian Electric Industries, Inc.	TECO Energy, Inc.
CMS Energy Corporation	NiSource Inc.	UIL Holdings Corporation
Consolidated Edison, Inc.	Northeast Utilities	Unisource Energy Corporation
Dominion Resources Inc.	NSTAR	Vectren Corporation
DPL Inc.	Pepco Holdings, Inc.	Westar Energy, Inc.
DTE Energy Company	PG&E Corporation	Wisconsin Energy Corporation
Duke Energy Corporation	Pinnacle West Capital Corp.	Xcel Energy Inc.

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, 2011, based on the 2008-2011 performance-measurement period. Payout for performance between points will be 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	%

See the Grants of Plan-Based Awards Table and the accompanying information for more information about threshold, target, and maximum payout opportunities for the 2008-2011 Performance Dividend Program.

Timing of Incentive Compensation

As discussed above, EPS and business unit financial performance goals for the 2008 annual incentive program were established at the February 2008 Compensation Committee meeting. Annual stock option grants were also made at that meeting. The establishment of incentive 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 2008 was the closing price of the Common Stock on the last trading day before the grant date. 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, including the named executive officers, participate in our funded Pension Plan after completing one year of service. Normal retirement benefits become payable when participants both attain age 65 and complete five years of participation. We also provide unfunded benefits that count salary and short-term incentive pay that is 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 24 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 the annual incentive and performance dividends 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 approved the change-in-control protection program in 1998. The program provides some level of severance benefits to all employees who are not part of a collective bargaining unit, if the conditions of the program are met, as described below. The Compensation Committee established this program and the levels of severance amount in order to provide certain compensatory protections to executives upon a change in control and thereby allow them to negotiate aggressively with a prospective purchaser. Providing such protections to our employees in general minimizes disruption during a pending or anticipated change in control. For all participants, payment and vesting occur only upon the occurrence of both an actual change in control and loss of the individual’s position.

Change-in-control protections, including severance pay and, in some situations, vesting or payment of long-term incentive 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 incentive amount assuming target-level performance. Less than 15 officers of the Company and its subsidiaries are entitled to this level of severance payment. Most officers of the Company and its subsidiaries are entitled to severance payments equal to two times their base salary plus the annual incentive amount assuming target-level performance. These amounts are consistent with that provided by other companies of our size and in our industry and were established based on market data provided to the Compensation Committee from its compensation consultant.

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.

Relocation Benefits

Mr. Bowers was named Chief Financial Officer of the Company in early 2008 and relocated from Birmingham, Alabama to Atlanta, Georgia at the Company’s request. The Company has a relocation program that generally provides the same level of benefits to all employees that relocate at the request of the Company. One benefit is a geographic relocation bonus of 10% of base salary. For Mr. Bowers, this amount is reported in the Bonus column in the Summary Compensation Table. Other standard benefits are provided such as movement of household goods, assistance with real estate closing costs, and loss on sale of a home. The standard program limits the loss on sale amount unless approved by the relocating employee’s executive management. For Mr. Bowers, the Compensation Committee approved the loss on sale of his home in Birmingham that was due to the downturn in the real estate market in Birmingham. The amount approved was approximately $300,000 plus tax reimbursement of approximately $153,000. These amounts, as well as all other relocation-related benefits, are reported in the All Other Compensation column in the Summary Compensation Table and the information accompanying it.

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. Mr. Ratcliffe is 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	3 Times	6 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 incentive compensation is paid. For tax purposes, in order to ensure that the annual incentive and performance dividend payouts are fully deductible under Section 162(m) of the Code, in February 2008, the Compensation Committee approved a formula that represented a maximum annual incentive amount payable (defined as 0.6% of the Company’s net income) and the maximum performance dividend amount payable for the 2008-2011 performance-measurement period (0.6% of the Company’s average net income during 2008-2011). For 2008 performance, the Compensation Committee used (for annual incentive), 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 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 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.

2009 Executive Compensation Program Changes

In early 2009, the Compensation Committee made certain key changes to the executive compensation program that affect all executive officers of the Company, including the named executive officers.

Perquisites

As described in the chart on page 25 of this CD&A, the Company provides limited perquisites for its executive officers, including the named executive officers. The principal perquisites provided are a financial planning benefit and club memberships. Other perquisites provided are described in the notes following the Summary Compensation Table and include: security system monitoring, spousal travel expenses when a business purpose for the travel exists, and other miscellaneous items. The value of the perquisites provided is considered personal income and the Company has provided tax gross-ups to cover the taxes owed on that income. Beginning in 2009, the Compensation Committee eliminated the tax gross-ups on perquisites, except relocation benefits, for all executive officers of the Company, including the named executive officers.

Stock Option Vesting

The Compensation Committee changed the stock option vesting provisions associated with retirement for the stock options granted to the executive officers of the Company, including the named executive officers, made in early 2009. Grants prior to 2009 vest ratably over a three year period, but vesting is accelerated upon retirement. For the grants made in 2009, unvested options are forfeited if the executive 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 executives who do accept positions with a peer company.

Base Salary Adjustments

Consistent with the broad-based compensation program, the Compensation Committee did not make any base salary adjustments in early 2009 for the named executive officers, except for Mr. Bowers. His base salary was adjusted because he was below the median of the market data.

Change-in-Control Program

The Compensation Committee has directed Towers Perrin to review best practices for change-in-control programs and has directed management to recommend any necessary changes to the program to meet those best practices. The review and any changes to the program will be completed in 2009 and effective in 2010.

COMPENSATION AND MANAGEMENT SUCCESSION 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, 2008 and in this Proxy Statement. The Board of Directors approved that recommendation.

Members of the Compensation Committee:

J. Neal Purcell, Chair

Jon A. Boscia

H. William Habermeyer, Jr.

Donald M. James

SUMMARY COMPENSATION TABLE FOR 2008

The Summary Compensation Table shows the amount and type of compensation received or earned in 2006, 2007, and 2008 for the Chief Executive Officer, the Chief Financial Officer, and the next three most highly-paid executive officers of the Company who served in 2008. 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		2008		1,118,090		—		—		1,666,774		5,267,878		1,481,217		79,378		9,613,337
Chairman, President,		2007		1,068,268		—		—		2,215,880		2,901,883		4,683,305		88,585		10,957,921
& CEO		2006		1,028,471		—		—		2,152,767		2,563,680		2,036,219		73,127		7,854,264


W. Paul Bowers		2008		557,476		56,510		—		201,808		1,001,174		185,472		770,837		2,773,277
Executive Vice		2007		502,366		—		—		291,202		669,586		582,095		42,282		2,087,531
President & CFO		2006		480,371		24,249		—		465,036		674,784		140,705		38,201		1,823,346


Thomas A. Fanning		2008		658,246		—		—		237,374		1,348,981		235,664		49,341		2,529,606
Executive Vice		2007		610,624		—		—		520,341		954,988		814,123		43,658		2,943,734
President & COO		2006		583,011		—		—		551,320		939,527		357,950		43,041		2,474,849


Michael D. Garrett		2008		679,641		—		—		248,343		1,283,734		666,453		48,411		2,926,582
President, Georgia		2007		613,731		—		—		413,075		828,844		2,259,654		47,440		4,162,744
Power Company		2006		575,100		29,288		—		391,843		967,002		880,636		47,183		2,891,052


Charles D. McCrary		2008		656,209		—		—		236,500		1,287,318		639,855		57,386		2,877,268
President, Alabama		2007		629,961		—		—		421,612		983,174		1,156,038		58,132		3,248,917
Power Company		2006		609,407		—		—		411,589		900,736		203,672		55,606		2,181,010

Column (d)

The amount shown for 2008 is a geographic relocation incentive as described in the CD&A. The amounts shown for 2006 were individual performance bonuses not based on pre-determined goals.

Column (e)

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

Column (f)

This column reports the dollar amounts recognized for financial statement reporting purposes with respect to 2008 in accordance with Financial Accounting Standards Board (FASB) Statement No. 123 (revised 2004), “Share Based Payments,”

disregarding any estimates of forfeitures relating 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 annual incentive program and the performance dividend program attributable to performance periods ended December 31, 2008 that are discussed in the CD&A. The amounts paid under each program to the named executive officers are shown below:


	Annual		Performance
	Incentive		Dividends		Total
Name	($)		($)		($)

D. M. Ratcliffe		1,682,906		3,584,972		5,267,878

W. P. Bowers		632,073		369,101		1,001,174

T. A. Fanning		742,786		606,195		1,348,981

M. D. Garrett		803,190		480,544		1,283,734

C. D. McCrary		690,387		596,931		1,287,318

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 2006, 2007, and 2008. The amount included for 2006 is the difference between the actuarial present values of the Pension Benefits measured as of September 30, 2005 and September 30, 2006 and the 2007 amount is the difference in 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 to comply with FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” 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 FASB Statement No. 87, “Employers’ Accounting for Pensions” 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 pension plans’ provisions were substantively the same as of September 30, 2005 and September 30, 2006. However, the present values of accumulated Pension Benefits as of September 30, 2007 reflect provisions that were made in 2007 regarding the form and timing of payments from the supplemental pension plans. Those changes brought the 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. Calculations of the present value of accumulated benefits prior to September 30, 2007 reflect 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, 2008, see the information following the Pension Benefits Table. The key

differences between assumptions used for the actuarial present values of accumulated benefits calculations as of September 30, 2007 and December 31, 2008 follow:


	•	Discount rate was increased to 6.75% as of December 31, 2008 from 6.3% as of September 30, 2007.

	•	15-month measurement period, as described above.

This column also reports above-market earnings on deferred compensation under the Deferred Compensation Plan (DCP). Above-market earnings are defined by the SEC as any amount above 120% of the applicable federal long-term rate as prescribed under Section 1274(d) of the Code. There were no above-market earnings on deferred compensation in 2008. 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		2008		1,481,217		0		1,481,217
		2007		4,646,301		37,004		4,683,305
		2006		2,002,835		33,384		2,036,219

W. P. Bowers		2008		185,472		0		185,472
		2007		577,633		4,462		582,095
		2006		136,681		4,024		140,705

T. A. Fanning		2008		235,664		0		235,664
		2007		809,570		4,553		814,123
		2006		353,902		4,048		357,950

M. D. Garrett		2008		666,453		0		666,453
		2007		2,250,828		8,826		2,259,654
		2006		872,674		7,962		880,636

C. D. McCrary		2008		639,855		0		639,855
		2007		1,150,499		5,539		1,156,038
		2006		198,676		4,996		203,672

Column (i)

This column reports the following items: perquisites; tax reimbursements by the Company on certain perquisites; Company contributions in 2008 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 2008 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 2008 are itemized below.


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

D. M. Ratcliffe		17,477		5,468		11,140		45,293		79,378

W. P. Bowers		439,382		303,362		11,392		16,701		770,837

T. A. Fanning		11,857		4,704		11,005		21,775		49,341

M. D. Garrett		7,460		6,289		11,730		22,932		48,411

C. D. McCrary		14,197		11,368		10,084		21,737		57,386

As discussed in the CD&A, the Compensation Committee eliminated tax reimbursements on all perquisites, except relocation benefits, effective January 1, 2009.

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 first 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. 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.

Personal Use of Company-Provided Club Memberships. The Company provides club memberships to certain officers, including all of the named executive officers. The memberships are provided for business use; however, personal use is permitted. The amount included reflects the pro-rata portion of the membership fees paid by the Company that are attributable to the named executive officers’ personal use. Direct costs associated with any personal use, such as meals, are paid for or reimbursed by the employee and therefore are not included.

Relocation Benefits. These benefits are provided to cover the costs associated with geographic relocation. In 2008, Mr. Bowers received relocation-related benefits of $426,991. See the CD&A for more information about relocation benefits.

Personal Use of Corporate-Owned Aircraft. The Company owns aircraft that are used to facilitate business travel. All flights on these aircraft must have a business purpose, except under very limited circumstances. There was no such personal use during 2008. Also, if seating is available, the Company permits a spouse or other family member to accompany an employee on a flight. However, because in such cases the aircraft is being used for a business purpose, there is no incremental cost associated with the family travel and no amounts are included for such travel. Any additional expenses incurred that are related to family travel are included.

Other Miscellaneous Perquisites. The amount included reflects the full cost to the Company of providing the following items: personal use of Company-provided tickets for sporting and other entertainment events and gifts distributed to and activities provided to attendees at Company-sponsored events.

GRANTS OF PLAN-BASED AWARDS IN 2008

The Grants of Plan-Based Awards Table provides information on stock option grants made and goals established for future payouts under the Company’s incentive compensation programs during 2008 by the Compensation Committee. In this table, the annual incentive 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		2/18/2008	PPP		508,260		1,129,467		2,484,827		703,280		35.78		1,666,774
		2/18/2008	PDP		229,231		2,292,314		4,584,628


W. P. Bowers		2/18/2008	PPP		190,721		423,824		932,413		85,151		35.78		201,808
		2/18/2008	PDP		23,601		236,012		472,024


T. A. Fanning		2/18/2008	PPP		224,331		498,514		1,096,731		100,158		35.78		237,374
		2/18/2008	PDP		38,762		387,615		775,230


M. D. Garrett		2/18/2008	PPP		234,698		521,552		1,147,414		104,786		35.78		248,343
		2/18/2008	PDP		30,727		307,271		614,541


C. D. McCrary		2/18/2008	PPP		223,506		496,681		1,092,698		99,789		35.78		236,500
		2/18/2008	PDP		38,169		381,692		763,383

Columns (c), (d), and (e)

The amounts reported as PPP reflect the amounts established by the Compensation Committee in early 2008 to be paid for certain levels of performance as of December 31, 2008 under the Company’s annual incentive program. The Compensation Committee assigns each named executive officer a target incentive opportunity, expressed as a percentage of base salary, that is paid for target-level performance under the annual incentive program. The target incentive opportunities established for the named executive officers for 2008 performance were 100% for Mr. Ratcliffe and 75% for Messrs. Bowers, Fanning, Garrett, and McCrary. The payout for threshold performance was set at 0.45 times the target incentive opportunity and the maximum amount payable was set at 2.20 times the target. The amount paid to each named executive officer under the annual incentive program for actual 2008 performance is included in the Non-Equity Incentive Plan Compensation column in the Summary Compensation Table and is itemized in the notes following that table. More information about the annual incentive program, including the applicable performance criteria established by the Compensation Committee, is provided in the CD&A.

The Company also has a long-term incentive 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 2008, the Compensation Committee established the performance dividend program goal for the four-year performance-measurement period beginning on January 1, 2008 and ending on December 31, 2011. The amount earned, if any, in 2011 based on the performance for 2008-2011 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 five percent for performance above the 10th percentile compared with the performance of the peer companies to 100% of the dividend if the Company’s total shareholder return is at or above the 90th percentile. That amount is then paid per option held at the end of the four-year period. The amount, if any, ultimately paid to the option holders, including the named executive officers, at the end of the last year of the 2008-2011 performance-measurement period will be based on (1) the Company’s total shareholder

return compared to that of its peer companies as of December 31, 2011, (2) the actual dividend, if any, paid in 2011 to our stockholders, and (3) the number of options held by the named executive officers on December 31, 2011.

The number of options held on December 31, 2011 will be affected by the number of additional options, if any, granted to the named executive officers prior to December 31, 2011 and the number of options, if any, exercised by the named executive officers prior to December 31, 2011. None of these components necessary to calculate the range of payout under the performance dividend program for the 2008-2011 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, 2008, as reported in columns (b) and (c) of the Outstanding Equity Awards at Fiscal Year-End Table, and the Common Stock dividend of $1.6625 per share paid to stockholders in 2008. 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
	2008		Performance		Performance		Performance
Name	(#)		($)		($)		($)

D. M. Ratcliffe		2,757,671		0.083125		0.83125		1.6625

W. P. Bowers		283,924		0.083125		0.83125		1.6625

T. A. Fanning		466,304		0.083125		0.83125		1.6625

M. D. Garrett		369,649		0.083125		0.83125		1.6625

C. D. McCrary		459,178		0.083125		0.83125		1.6625

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 18, 2008. Under the terms of the Omnibus Incentive Compensation Plan, the exercise price was set at the closing price ($35.78 per share) on the last trading day prior to the grant date, which was February 15, 2008.

Column (h)

The value of stock options granted in 2008 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 2008 FISCAL YEAR-END

This table provides information pertaining to all outstanding stock options held by the named executive officers as of December 31, 2008.


								Stock Awards
											Equity
											Incentive
											Plan
	Option Awards									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
		345,826		172,913		33.81	02/20/2016
		179,279		358,556		36.42	02/19/2017
		0		703,280		35.78	02/18/2018


W. P. Bowers		60,576		0	—	32.70	02/18/2015	—	—	—	—
		45,011		22,506		33.81	02/20/2016
		23,560		47,120		36.42	02/19/2017
		0		85,151		35.78	02/18/2018


T. A. Fanning		27,314		0	—	27.975	02/14/2013	—	—	—	—
		63,215		0		29.50	02/13/2014
		80,843		0		32.70	02/18/2015
		63,595		31,797		33.81	02/20/2016
		33,128		66,254		36.42	02/19/2017
		0		100,158		35.78	02/18/2018


M. D. Garrett		17,806		0	—	29.50	02/13/2014	—	—	—	—
		52,376		0		32.70	02/18/2015
		62,947		31,473		33.81	02/20/2016
		33,421		66,840		36.42	02/19/2017
		0		104,786		35.78	02/18/2018


C. D. McCrary		71,424		0	—	29.50	02/13/2014	—	—	—	—
		86,454		0		32.70	02/18/2015
		66,119		33,059		33.81	02/20/2016
		34,111		68,222		36.42	02/19/2017
		0		99,789		35.78	02/18/2018

Stock options vest one-third per year on the anniversary of the grant date. Options granted from 2002 through 2005, with expiration dates from 2012 through 2015, were fully vested as of December 31, 2008. The options granted in 2006, 2007, and 2008 become fully vested as shown below.


Year Option Granted	Expiration Date	Date Fully Vested


2006	February 20, 2016	February 20, 2009

2007	February 19, 2017	February 19, 2010

2008	February 18, 2018	February 18, 2011

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 the section entitled 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 FISCAL 2008

This table reports the number of shares acquired upon the exercise of stock options during 2008 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	(#)		($)		(#)	($)
(a)	(b)		(c)		(d)	(e)


D. M. Ratcliffe		0		0	0	0

W. P. Bowers		148,279		1,396,033	0	0

T. A. Fanning		15,000		137,514	0	0

M. D. Garrett		0		0	0	0

C. D. McCrary		0		0	0	0

PENSION BENEFITS AND VALUES AT 2008 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		36.83		974,407	—
	Supplemental Benefit Plan (Pension-Related)		36.83		11,314,975	—
	Supplemental Executive Retirement Plan		36.83		3,485,250	—
	Supplemental Pension Agreement		0		0

W. P. Bowers	Pension Plan		28.67		455,034	—
	Supplemental Benefit Plan (Pension-Related)		28.67		1,502,158	—
	Supplemental Executive Retirement Plan		28.67		502,073	—
	Supplemental Pension Agreement		0		0

T. A. Fanning	Pension Plan		27.00		421,385	—
	Supplemental Benefit Plan (Pension-Related)		27.00		2,027,730	—
	Supplemental Executive Retirement Plan		27.00		655,003	—
	Supplemental Pension Agreement		0		0

M. D. Garrett	Pension Plan		39.75		997,963	—
	Supplemental Benefit Plan (Pension-Related)		39.75		4,993,234	—
	Supplemental Executive Retirement Plan		39.75		1,605,911	—
	Supplemental Pension Agreement		0		0

C. D. McCrary	Pension Plan		34.00		753,849	—
	Supplemental Benefit Plan (Pension-Related)		34.00		3,597,419	—
	Supplemental Executive Retirement Plan		34.00		1,168,431	—
	Supplemental Pension Agreement		0		0

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.

The 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 2008 was $230,000.

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 high-paid employees any benefits that the Pension Plan cannot pay due to statutory pay/benefit limits and voluntary pay deferrals. The SBP-P’s vesting, early retirement, and disability provisions mirror those of the Pension Plan.

The amounts paid by the SBP-P are based on the additional monthly benefit that the Pension Plan would pay if the statutory limits and pay deferrals were ignored. When an SBP-P participant separates from service, vested monthly benefits provided by the benefit formulas are converted into a single sum value. It equals the present value of what would have been paid monthly for an actuarially determined average post-retirement lifetime. The discount rate used in the calculation is based on the 30-year Treasury yields for the September preceding the calendar year of separation, but not more than six percent.

Vested participants terminating prior to becoming eligible to retire will be paid their single sum value as of September 1 following the calendar year of separation. If the terminating participant is retirement eligible, the single sum value will be paid in 10 annual installments starting shortly after separation. The unpaid balance of a retiree’s single sum will be credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a “key man” under Section 409A of the Code, the first installment will be delayed for six months after the date of separation.

If an SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participant’s death occurs prior to age 50, the installments will be paid to a survivor as if the participant had survived to age 50.

The Southern Company Supplemental Executive Retirement Plan (SERP)

The SERP is also an unfunded retirement plan that is not tax-qualified. This plan provides to high-paid employees additional benefits that the Pension Plan and the SBP-P would pay if the 1.7% offset formula calculations reflected a portion of annual cash incentives. To derive the SERP benefits, a final average pay is determined reflecting participants’ base rates of pay and their 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.

Assumptions

The following assumptions were used in the present value calculations:


•	Discount rate — 6.75% as of December 31, 2008
•	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:


	•	Unmarried retirees: 100% elect a single life annuity
	•	Married retirees: 20% elect a single life annuity; 40% elect a joint and 50% survivor annuity; and 40% elect a joint and 100% survivor annuity
	•	Percent married at retirement — 80% of males and 70% of females


•	Spouse ages — Wives two years younger than their husbands
•	Incentives earned but unpaid as of the measurement date — 135% of target percentages times base rate of pay for year incentive is earned
•	Installment determination — 4.75% discount rate for single sum calculation and 6.75% 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 2008 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		45,293		211,020		0		9,488,438

W. P. Bowers		201,290		16,701		41,367		0		1,040,417

T. A. Fanning		65,524		21,775		28,234		0		1,072,286

M. D. Garrett		0		22,932		51,335		0		1,305,970

C. D. McCrary		0		21,737		32,387		0		1,136,398

The Company provides the Deferred Compensation Plan (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 the annual incentive and the performance dividends 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 held by a Company stockholder. During 2008, the rate of return in the Stock Equivalent Account was 0.03%, which was the Company’s total shareholder return for 2008.

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 range of interest rates earned on amounts deferred during 2008 in the Prime Equivalent Account was 3.25% to 6.00%.

Column (b)

This column reports the actual amounts of compensation deferred under the DCP by each named executive officer in 2008 which can include up to 50% of salary and up to 100% of incentive compensation paid in 2008. Incentive compensation is paid early in the year following the year it is earned. Therefore, the amount reported in this column attributable to incentive compensation was earned as of December 31, 2007. The amount of incentive compensation earned as of December 31, 2008 that a named executive officer has elected to defer is reported in the Summary Compensation Table but is not included in this column because it was not payable until early 2009.

Column (c)

This column reports contributions under the SBP. The SBP is a nonqualified deferred compensation plan under which employer matching contributions are made that are prohibited from being made in the ESP because they are above stated limits under the ESP, or, if applicable, above legal limits under the Code. These 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 on both compensation the named executive officers elected to defer and earnings 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 2008		Prior to 2008 and
	and Reported in Prior		Reported in Prior Years’
	Years’ Proxy Statements		Proxy Statements		Total
Name	($)		($)		($)


D. M. Ratcliffe		5,381,881		246,788		5,628,669

W. P. Bowers		86,675		12,199		98,874

T. A. Fanning		772,898		82,163		855,061

M. D. Garrett		0		69,996		69,996

C. D. McCrary		489,924		151,114		641,038

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, 2008 and assumes that the price of Common Stock is the closing market price on December 31, 2008.

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 is generally satisfied when there is a material reduction in salary, incentive 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 benefit plans and therefore any termination of employment also would be a retirement.


		Lay Off
		(Involuntary			Involuntary
		Termination		Death or	Termination
Program	Retirement/Retirement Eligible	Not For Cause)	Resignation	Disability	(For Cause)


Pension Benefit 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 or Resignation, as the case may be.

Annual Incentive 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.	Continues for one year.	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 Deferred Compensation Plan.	Same as Retirement.

The chart below describes the treatment of payments under compensation and benefit programs under different change-in-control events (Change-in-Control Chart). The Pension Plan, the Deferred Compensation Plan, and the Supplemental Benefit Plan 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 Supplemental Executive Retirement Plan 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 Incentive Program	If no plan termination; is paid at greater of target or actual performance. If plan 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, if the annual incentive program still in effect, pro-rated at target performance level.

Performance Dividend Program	If no plan termination; is paid at greater of target or actual performance. If plan 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, if the performance dividend program is still in effect, greater of actual or target performance level for year of severance only.

Stock Options	Not affected by change-in-control events.	Same as Southern Change in Control I.	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 incentive 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, 2008.

Pension Benefits

The amounts that would have become payable to the named executive officers if the Traditional Termination Events occurred as of December 31, 2008 under the Pension Plan, the SBP-P, and the SERP are itemized in the chart below. The amounts shown under the column “Retirement” are amounts that would have become payable to the named executive officers since all were retirement eligible on December 31, 2008 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		9,062		All plans treated as		4,937
	Supplemental Benefit Plan		1,438,814		retiring		1,438,814
	Supplemental Executive Retirement Plan		443,185				443,185

W. P. Bowers	Pension Plan		4,579		All plans treated as		3,873
	Supplemental Benefit Plan		241,283		retiring		241,283
	Supplemental Executive Retirement Plan		80,645				80,645

T. A. Fanning	Pension Plan		4,237		All plans treated as		3,646
	Supplemental Benefit Plan		326,673		retiring		326,673
	Supplemental Executive Retirement Plan		105,523				105,523

M. D. Garrett	Pension Plan		9,445		All plans treated as		5,359
	Supplemental Benefit Plan		659,790		retiring		659,790
	Supplemental Executive Retirement Plan		212,200				212,200

C. D. McCrary	Pension Plan		7,386		All plans treated as		4,648
	Supplemental Benefit Plan		514,157		retiring		514,157
	Supplemental Executive Retirement Plan		166,997				166,997

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, 2008 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 table above; they are not paid in addition to those amounts.


	SBP-P		SERP		Total
Name	($)		($)		($)


D. M. Ratcliffe		14,388,141		4,431,850		18,819,991

W. P. Bowers		2,412,831		806,452		3,219,283

T. A. Fanning		3,266,730		1,055,228		4,321,958

M. D. Garrett		6,597,901		2,122,000		8,719,901

C. D. McCrary		5,141,567		1,669,966		6,811,533

The pension benefit amounts in the tables above were calculated as of December 31, 2008 assuming payments would begin as soon as possible under the terms of the plans. Accordingly, appropriate early retirement reductions were applied. Any unpaid incentives were assumed to be paid at 1.35 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 4.75% discount rate as prescribed by the terms of the plan.

Annual Incentive

Because this section assumes that a termination or change-in-control event occurred on December 31, 2008, there is no amount that would be payable other than what was reported and described in the Summary Compensation Table because actual performance in 2008 exceeded target performance.

Performance Dividends

Because the assumed termination date is December 31, 2008, 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 Common Stock on December 31, 2008 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		1,234,749		2,757,671		8,991,151

W. P. Bowers		154,777		283,924		620,735

T. A. Fanning		198,209		466,304		1,552,381

M. D. Garrett		203,099		369,649		845,952

C. D. McCrary		201,070		459,178		1,404,906

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 incentive 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 incentive 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, 2008 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		2,966,766

T. A. Fanning		3,489,597

M. D. Garrett		3,650,862

C. D. McCrary		3,476,771

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

During 2008, Mr. David M. Huddleston, a son-in-law of Mr. Michael D. Garrett, an executive officer of the Company, was employed by a subsidiary of the Company. Mr. Huddleston was employed by Alabama Power Company as an Engineering Supervisor and received compensation in 2008 of $127,220. Ms. Donna D. Smith, sister of Mr. Andrew J. Dearman, III, who was an executive officer of the Company during 2008, was employed at Southern Company Services, Inc. as a Human Resources Director and received compensation in 2008 of $350,449.

The Company does not have a written policy pertaining solely to the approval or ratification of “related party transactions.” However, the Company has a Code of Ethics as well as employment and compensation policies that govern the hiring and compensating of all employees, including those named above. The Company also has a Contract Guidance Manual and other formal written procurement policies and procedures that guide the purchase of goods and services, including requiring competitive bids for most transactions above $10,000 or approval based on documented business needs for sole sourcing arrangements.

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.

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

APPENDIX C

2008 ANNUAL REPORT

Table of Contents



Southern Company Common Stock and Dividend Information			ii


Five-Year Cumulative Performance Graph			ii


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-4


Quantitative and Qualitative Disclosures about Market Risk			C-36


Cautionary Statement Regarding Forward-Looking Statements			C-41


Consolidated Statements of Income			C-42


Consolidated Statements of Cash Flows			C-43


Consolidated Balance Sheets			C-44


Consolidated Statements of Capitalization			C-46


Consolidated Statements of Common Stockholders’ Equity			C-48


Consolidated Statements of Comprehensive Income			C-48


Notes to Financial Statements			C-49


Selected Consolidated Financial and Operating Data			C-98


Board of Directors			C-100


Management Council			C-102


Stockholder Information			C-104

SOUTHERN COMPANY COMMON STOCK AND DIVIDEND INFORMATION

The common stock of Southern Company is listed and traded on the New York Stock Exchange. The common stock is also traded on regional exchanges across the United States. The high and low stock prices as reported on the New York Stock Exchange for each quarter of the past two years were as follows:


	High		Low		Dividend


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
2007
First Quarter	$	37.25	$	34.85	$	0.3875
Second Quarter		38.90		33.50		0.4025
Third Quarter		37.70		33.16		0.4025
Fourth Quarter		39.35		35.15		0.4025

On March 30, 2009, Southern Company had approximately 170,806 registered stockholders.

FIVE-YEAR CUMULATIVE PERFORMANCE GRAPH

This performance graph compares the cumulative total shareholder return on the Company’s common stock with the Standard & Poor’s Electric Utility Index and the Standard & Poor’s 500 index for the past five years. The graph assumes that $100 was invested on December 31, 2003 in the Company’s common stock and each of the above indices and that all dividends were reinvested. The stockholder return shown below for the five-year historical period may not be indicative of future performance.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company and Subsidiary Companies 2008 Annual Report

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

Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2008.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2008. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein.

/s/ David M. Ratcliffe

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

/s/ W. Paul Bowers

W. Paul Bowers
Executive Vice President and Chief Financial Officer

February 25, 2009

C-1

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, 2008 and 2007, and the related consolidated statements of income, comprehensive income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. We also have audited the Company’s internal control over financial reporting as of December 31, 2008, 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.

C-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (continued)

In our opinion, the consolidated financial statements (pages C-42 to C-96) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, 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, 2009

C-3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2008 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 in the midst of the current economic downturn, 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. Since 2005, the traditional operating companies have completed a number of regulatory proceedings that provide for the timely recovery of costs. 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. 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. The Company continues to face regulatory challenges related to transmission and market power issues at the national level.

Southern Company’s other business activities include leveraged lease projects, telecommunications, and energy-related services. Management continues to evaluate the contribution of each of these remaining 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 charges related to leveraged leases. Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The fossil/hydro 2008 Peak Season EFOR of 1.68% was better than the target. The nuclear generating fleet also uses Peak Season EFOR as an indicator of availability and efficient generation fleet operations during the peak season. The nuclear 2008 Peak Season EFOR of 1.98% 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 2008 was better than the target for these reliability measures.

C-4

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Southern Company’s investments include three leveraged lease transactions whose tax deductions have been challenged by the Internal Revenue Service (IRS). Ongoing settlement negotiations with the IRS resulted in a charge to income of $83 million, or 11 cents per share, in 2008. Southern Company management uses EPS, excluding leveraged lease charges, to evaluate the performance of Southern Company’s ongoing business activities. Southern Company believes the presentation of earnings and EPS excluding the leveraged lease charges is useful for investors because it provides investors with additional information for purposes of comparing Southern Company’s performance for such periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with generally accepted accounting principles.

Southern Company’s 2008 results compared with its targets for some of these key indicators are reflected in the following chart:


	2008 Target		2008 Actual
Key Performance Indicator	Performance		Performance
	Top quartile in
Customer Satisfaction	customer surveys		Top quartile
Peak Season EFOR — fossil/hydro	2.75% or less			1.68	%
Peak Season EFOR — nuclear	2.00% or less			1.98	%
Basic EPS	$	2.28 — $2.36	$	2.26
EPS, excluding leveraged lease charges	—		$	2.37

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The financial performance achieved in 2008 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 was $1.74 billion in 2008, an increase of $8 million from the prior year. Compared with the prior year, increases in retail rates and increases in revenues from market-response rates to large commercial and industrial customers were mostly offset by higher asset depreciation, milder summer temperatures compared to 2007, higher non-fuel operations and maintenance expenses, charges related to the leveraged lease business, and exiting the synthetic fuel business in 2007. Net income was $1.73 billion in 2007 and $1.57 billion in 2006, reflecting a 10.2% increase and a 1.1% decrease, respectively, over the prior year. Basic EPS was $2.26 in 2008, $2.29 in 2007, and $2.12 in 2006. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.25 in 2008, $2.28 in 2007, and $2.10 in 2006.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.6625 in 2008, $1.595 in 2007, and $1.535 in 2006. In January 2009, Southern Company declared a quarterly dividend of 42 cents per share. This is the 245th 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 2008, the actual payout ratio was 73.5% while the payout ratio of net income excluding leveraged lease charges was 70.1%.

C-5

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 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
	2008		2008		2007			2006
	(in millions)
Electric operating revenues	$	17,000	$	1,860	$	1,052		$	810

Fuel		6,817		973		701			655
Purchased power		815		300		(28	)		(188	)
Other operations and maintenance		3,584		111		183			70
Depreciation and amortization		1,414		199		51			27
Taxes other than income taxes		794		56		23			39

Total electric operating expenses		13,424		1,639		930			603

Operating income		3,576		221		122			207
Other income (expense), net		145		24		68			(9	)
Interest expense and dividends		837		25		61			75
Income taxes		1,037		87		1			50

Net income	$	1,847	$	133	$	128		$	73

Electric Operating Revenues

Details of electric operating revenues were as follows:


	Amount
	2008			2007			2006
	(in millions)
Retail — prior year	$	12,639		$	11,801		$	11,165
Estimated change in —
Rates and pricing		668			161			9
Sales growth		—			60			115
Weather		(106	)		54			35
Fuel and other cost recovery		854			563			477

Retail — current year		14,055			12,639			11,801
Wholesale revenues		2,400			1,988			1,822
Other electric operating revenues		545			513			465

Electric operating revenues	$	17,000		$	15,140		$	14,088

Percent change		12.3	%		7.5	%		6.1	%

Retail revenues increased $1.4 billion, $838 million, and $636 million in 2008, 2007, and 2006, respectively. The significant factors driving these changes are shown in the preceding table. The increase in rates and pricing in 2008 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

C-6

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

plan, as ordered by the Georgia PSC. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” for additional information. Also contributing to the 2008 increase was an increase in revenues from market-response rates to large commercial and industrial customers at Georgia Power. 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 at Georgia Power. The 2006 increase in rates and pricing when compared to the prior year was not material. See “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth 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. Southern Company’s average wholesale contract extends more than 14 years and, as a result, the Company has significantly limited its remarketing risk.

In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the average cost of fuel per net kilowatt-hour (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 9.9% increase in the average cost of fuel per net KWH generated. Excluding fuel, wholesale revenues were flat when compared to the prior year.

In 2006, wholesale revenues increased $155 million primarily as a result of a 10.0% increase in the average cost of fuel per net KWH generated, as well as revenues resulting from new PPAs in 2006. In addition, Southern Company assumed four PPAs through the acquisitions of Plants DeSoto and Rowan in June and September 2006, respectively. The 2006 increase was partially offset by a decrease in short-term opportunity sales.

Revenues associated with PPAs and opportunity sales were as follows:


	2008		2007		2006
	(in millions)
Other power sales —
Capacity and other	$	538	$	533	$	499
Energy		1,319		989		841

Total	$	1,857	$	1,522	$	1,340

C-7

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 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 2.1% in 2008, decreased 0.8% in 2007, and increased 0.2% in 2006. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, because the energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The capacity and energy components of the unit power sales contracts were as follows:


	2008		2007		2006
	(in millions)
Unit power sales —
Capacity	$	223	$	202	$	208
Energy		320		264		274

Total	$	543	$	466	$	482

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2008 and the percent change by year were as follows:


	KWHs		Percent Change

	2008		2008			2007			2006
	(in billions)
Residential		52.3		(2.0	)%		1.8	%		2.5	%
Commercial		54.4		(0.4	)		3.2			2.2
Industrial		52.7		(3.7	)		(0.7	)		(0.2	)
Other		0.9		(2.9	)		4.4			(7.6	)

Total retail		160.3		(2.1	)		1.4			1.4
Wholesale		39.3		(3.4	)		5.9			3.7

Total energy sales		199.6		(2.3	)		2.3			1.9

KWH sales by quarter for 2008 compared to the same periods in 2007 were as follows:

KWHs

Percent Change

Total

Quarter Ended

Retail

Wholesale

Energy Sales

Retail

Wholesale

Energy Sales

(in millions)

March 2008

38,576

9,590

48,166

1.4

(1.9

0.7

June 2008

39,882

10,049

49,931

(1.2

)

1.0

(0.7

)

September 2008

45,800

10,969

56,769

(4.6

)

(2.2

)

(4.1

)

December 2008

36,001

8,760

44,761

(3.3

)

(10.6

)

(4.8

)

Changes in retail energy sales are comprised of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 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

C-8

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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. Retail energy sales in 2006 increased 2.3 billion KWHs as a result of customer growth of 1.7%, sustained economic growth primarily in the residential and commercial customer classes, and favorable weather in 2006 when compared to 2005.

Wholesale energy sales decreased by 1.4 billion KWHs in 2008, increased by 2.3 billion KWHs in 2007, and increased by 1.4 billion KWHs in 2006. 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. The increase in wholesale energy sales in 2006 was related primarily to the new PPAs discussed previously under “Electric Operating Revenues.”

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 Southern Company’s electricity generated and purchased were as follows:


	2008		2007		2006
Total generation (billions of KWHs)		198		206		201
Total purchased power (billions of KWHs)		11		8		8

Sources of generation (percent) —
Coal		68		70		70
Nuclear		15		14		15
Gas		16		15		13
Hydro		1		1		2

Cost of fuel, generated (cents per net KWH) —
Coal		3.27		2.60		2.40
Nuclear		0.50		0.50		0.47
Gas		7.58		6.64		6.63

Average cost of fuel, generated (cents per net KWH)		3.52		2.89		2.63
Average cost of purchased power (cents per net KWH)		7.85		7.20		6.82

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 25.8% 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

In 2006, fuel and purchased power expenses were $5.7 billion, an increase of $467 million or 8.9% above the prior year costs. This increase was primarily the result of a $367 million net increase in the average cost of fuel and purchased power and a $100 million increase related to higher net KWHs generated and purchased.

Over the last several years, coal prices have been influenced by a worldwide increase in demand from developing countries, as well as increases in mining and fuel transportation costs. In the first half of 2008, coal prices reached unprecedented high levels primarily due to increased demand following more moderate pricing in 2006 and 2007. Despite these fluctuations, fuel inventories have been adequate and fuel supply markets have been sufficient to meet expected fuel requirements. Demand for natural gas in the United States also increased in 2007 and the first half of 2008. However, natural gas supplies increased in the last half of 2008 as a result of increased production and higher storage levels due in part to weak industrial demand. Both coal and natural gas prices moderated in the second half of 2008 as the result of a recessionary economy. During 2008, uranium prices continued to moderate from the highs set during 2007. While worldwide uranium production levels appear to have increased slightly since 2007, 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 $3.6 billion, $3.5 billion, and $3.3 billion, increasing $111 million, $183 million, and $70 million in 2008, 2007, and 2006, respectively. Discussion of significant variances for components of other operations and maintenance expenses follows.

Other production expenses at fossil, hydro, and nuclear plants increased $63 million, $128 million, and $3 million in 2008, 2007, and 2006, respectively. Production expenses fluctuate from year to year due to variations in outage schedules and normal increases in 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. See Note 1 to the financial statements under “Property, Plant, and Equipment” for additional information regarding 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 Orlando Utilities Commission. 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. The 2006 increase in other production expenses when compared to the prior year was not material.

Transmission and distribution expenses increased $4 million, $21 million, and $30 million in 2008, 2007, and 2006, respectively. Transmission and distribution expenses fluctuate from year to year due to variations in maintenance schedules and normal increases in costs. 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. Transmission and distribution expenses increased in 2006 primarily due to expenses associated

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

with recovery of prior year storm costs through natural disaster recovery clauses in accordance with an accounting order approved by the Alabama PSC and maintenance associated with additional investment in distribution to meet customer growth.

Customer sales and service expenses increased $32 million, $7 million, and $9 million in 2008, 2007, and 2006, respectively. Customer sales and service expenses increased in 2008 primarily as a result of an increase in customer account expenses, including a $13 million increase in uncollectible accounts expense, a $9 million increase in meter reading and related supervision expenses, and an $8 million increase for records and collections. The 2007 and 2006 increases in customer sales and service expenses were not material when compared to the prior years.

Administrative and general expenses increased $10 million, $28 million, and $29 million in 2008, 2007, and 2006, respectively. The 2008 increase in administrative and general expenses was not material when compared to the prior year. 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. Administrative and general expenses increased in 2006 primarily as a result of a $17 million increase in salaries and wages and a $24 million increase in pension expense, partially offset by a $16 million reduction in medical expenses.

Depreciation and 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.

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.

Depreciation and amortization increased $27 million in 2006 primarily as a result of the acquisitions of Plants DeSoto, Rowan, and Oleander in June 2006, September 2006, and June 2005, respectively, and an increase in the amortization expense of the Mississippi Power regulatory liability related to Plant Daniel capacity. An increase in depreciation rates at Southern Power also contributed to the 2006 increase. Partially offsetting the 2006 increase was a reduction in the amortization expense of a Georgia Power regulatory liability related to the levelization of certain purchased power capacity costs.

Taxes Other Than Income Taxes

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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. Taxes other than income taxes increased $39 million in 2006 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales, as well as increases in property taxes associated with additional plant in service.

Other Income (Expense), Net

Other income (expense), net increased $24 million in 2008 primarily as a result of an increase in allowance for equity funds used during construction 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 $68 million in 2007 primarily as a result of an increase in allowance for equity funds used during construction related to additional investments in environmental equipment at generating plants and transmission and distribution projects mainly at Alabama Power and Georgia Power. The 2006 decrease in other income (expense), net when compared to the prior year was not material.

Interest Expense and Dividends

Total interest charges and other financing costs increased by $25 million in 2008 primarily as a result of an $82 million increase associated with $1.7 billion in additional debt and preference stock 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 $61 million in 2007 primarily as a result of a $72 million increase associated with $1.2 billion in additional debt and preference stock 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.

Total interest charges and other financing costs increased by $75 million in 2006 primarily due to a $78 million increase associated with $708 million in additional debt outstanding at December 31, 2006 compared to December 31, 2005 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the 2006 increase was $7 million associated with higher average interest rates on existing variable rate debt, partially offset by $6 million of additional capitalized interest associated with construction projects and $3 million in lower other interest costs.

Income Taxes

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 allowance for equity funds used during construction, which is not taxable. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

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 allowance for equity funds used during construction, which is not taxable; and an increase in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Income taxes increased $50 million in 2006 primarily due to higher pre-tax earnings as compared to 2005 and the impact of a 2005 accounting order approved by the Alabama PSC to return certain regulatory liabilities related to deferred taxes to Alabama Power’s retail customers.

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 and synthetic fuel projects, telecommunications, and energy-related services. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various energy-related projects, including leveraged lease and synthetic fuel projects that receive tax benefits, which have contributed significantly to the economic results of these investments; 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 Company’s investment in synthetic fuel projects ended at December 31, 2007. A condensed statement of income for Southern Company’s other business activities follows:


				Increase (Decrease)
	Amount			from Prior Year
	2008			2008			2007			2006
				(in millions)
Operating revenues	$	127		$	(86	)	$	(55	)	$	(8	)

Other operations and maintenance		165			(44	)		(29	)		(59	)
Depreciation and amortization		29			(1	)		(6	)		(3	)
Taxes other than income taxes		3			—			—			(1	)

Total operating expenses		197			(45	)		(35	)		(63	)

Operating income (loss)		(70	)		(41	)		(20	)		55
Equity in income (losses) of unconsolidated subsidiaries		10			35			35			62
Leveraged lease income (losses)		(85	)		(125	)		(29	)		(5	)
Other income (expense), net		12			(29	)		73			(19	)
Interest expense		94			(28	)		(27	)		48
Income taxes		(122	)		(7	)		53			136

Net income (loss)	$	(105	)	$	(125	)	$	33		$	(91	)

Operating Revenues

Southern Company’s non-electric operating revenues from these other businesses decreased $86 million in 2008 primarily as a result of 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 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. The $8 million decrease in 2006 primarily resulted from a $21 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and lower equipment and accessory sales. The 2006 decrease was partially offset by a $12 million increase in fuel procurement service revenues.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other businesses 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. Other operations and maintenance expenses decreased $59 million in 2006 primarily as a result of $32 million of lower production expenses related to the termination of Southern Company’s membership interest in one of the synthetic fuel entities, $13 million attributed to the wind-down of one of the Company’s energy-related services businesses, and $7 million of lower expenses resulting from the March 2006 sale of a subsidiary that provided rail car maintenance services.

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 of unconsolidated subsidiaries increased $35 million in 2008 as a result of Southern Company terminating its investment in synthetic fuel projects at December 31, 2007. Equity in losses of unconsolidated subsidiaries decreased $35 million in 2007 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. Equity in losses of unconsolidated subsidiaries decreased $62 million in 2006 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. The 2006 decrease also resulted from lower operating expenses while the production facilities at the other synthetic fuel entity were idled from May to September 2006 due to higher oil prices.

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 losses increased $125 million in 2008 as a result of Southern Company’s decision to participate in a settlement with the IRS related to deductions for several sale-in-lease-out (SILO) transactions and the resulting application of Financial Accounting Standards Board (FASB) Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2). See Note 3 to the financial statements under “Income Tax Matters — Leveraged Leases” for further information. Leveraged lease income decreased $29 million in 2007 as a result of the adoption of FSP 13-2, as well as an expected decline in leveraged lease income over the terms of the leases. The 2006 decrease in leveraged lease income when compared to the prior year was not material.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Other Income (Expense), Net

Other income (expense), net for these other businesses decreased $29 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 $73 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. Other income (expense), net decreased $19 million in 2006 primarily as a result of a $25 million decrease related to changes in the value of derivative transactions in the synthetic fuel business and the previously mentioned impairment and release of contractual obligations.

Interest Expense

Total interest charges and other financing costs for these other businesses decreased $28 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 $27 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. Total interest charges and other financing costs increased by $48 million in 2006 primarily as a result of a $19 million increase associated with $149 million in additional debt outstanding at December 31, 2006 as compared to December 31, 2005 and higher interest rates associated with the issuance of new long-term debt. Also contributing to the increase were $12 million associated with higher average interest rates on existing variable rate debt, a $6 million loss on the early redemption of long-term debt payable to affiliated trusts in January 2006, and a $16 million loss on the repayment of long-term debt payable to affiliated trusts in December 2006. The 2006 increase was partially offset by $4 million in lower other interest costs.

Income Taxes

Income taxes for these other businesses 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. Income taxes increased $136 million in 2006 primarily as a result of a $111 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, curtailing production at the other synthetic fuel entity from May to September 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Effects of Inflation

The traditional operating companies and Southern Power are subject to rate regulation and party to long-term contracts that are generally based on the recovery of historical costs. When historical costs are included, or when inflation exceeds projected costs used in rate regulation or in market-based prices, the effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. In addition, the income tax laws are based on historical costs. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss or the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt, preferred securities, preferred stock, and preference stock. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the traditional operating companies’ approved electric rates.

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.

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 all 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. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales during the current economic downturn, 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, and the successful remarketing of capacity as current contracts expire. Recent recessionary conditions have negatively impacted sales growth for the traditional operating companies and may negatively impact wholesale capacity revenues at Southern Power. The timing and extent of the economic recovery will impact future earnings.

Southern Company system generating capacity increased 659 megawatts due to Southern Power’s completion of Franklin Unit 3 in June 2008. 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 Projects” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.

The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. On July 24, 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power 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, and the ultimate outcome of these matters cannot be determined at this time.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 in either of these cases could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Carbon Dioxide Litigation

New York Case

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

Kivalina Case

On February 26, 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 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. On June 30, 2008, all defendants filed motions to dismiss this case. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

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

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costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2008, Southern Company had invested approximately $6.3 billion in capital projects to comply with these requirements, with annual totals of $1.6 billion, $1.5 billion, and $661 million for 2008, 2007, and 2006, respectively. The Company expects that capital expenditures to assure compliance with existing and new statutes and regulations will be an additional $1.4 billion, $737 million, and $871 million for 2009, 2010, and 2011, 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 emission 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, 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 2008, the Company had spent approximately $5.4 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.

In 2004, the EPA designated nonattainment areas under an eight-hour ozone standard. Areas within Southern Company’s service area that were designated as nonattainment under the eight-hour ozone standard included Macon (Georgia), Birmingham (Alabama), and a 20-county area within metropolitan Atlanta. The Macon and Birmingham areas have since been redesignated as attainment areas by the EPA, and maintenance plans to address future exceedances of the standard have been approved for both areas. State plans for bringing the Atlanta area into attainment with this standard were due to the EPA in 2007; however, in December 2006, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA rules designed to provide states with the guidance necessary to develop those plans. State plans could require additional reductions in NO_xemissions from power plants. On March 12, 2008, the EPA issued a final rule establishing a more stringent eight-hour ozone standard which will likely result in designation of new nonattainment areas within Southern Company’s service territory. The EPA is expected to publish those designations in 2010 and require state implementation plans for any nonattainment areas by 2013.

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 were due by April 5, 2008 but have not been finalized. These state plans 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. On December 18, 2008, the EPA designated the Birmingham, Alabama area as nonattainment for the 24-hour standard. A state implementation plan for this nonattainment area is due in 2012.

The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the rule. The rule calls for additional

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Southern Company and Subsidiary Companies 2008 Annual Report

reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. On July 11, 2008, in response to petitions brought by certain states and regulated industries challenging particular aspects of CAIR, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating CAIR in its entirety and remanding it to the EPA for further action consistent with its opinion. On December 23, 2008, however, the U.S. Court of Appeals for the District of Columbia Circuit altered its July decision in response to a rehearing petition and remanded CAIR to the EPA without vacatur, thereby leaving 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. Emission reductions are being accomplished by the installation of emission controls at Southern Company’s coal-fired facilities and/or by the purchase of emission allowances. The full impact of the court’s remand and the outcome of the EPA’s future rulemaking in response cannot be determined at this time.

The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized in July 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves (1) the application of Best Available Retrofit Technology (BART) to certain sources built between 1962 and 1977 and (2) the application of any additional emissions reductions which may be deemed necessary for each designated area to achieve reasonable progress by 2018 toward the natural conditions goal. Thereafter, for each 10-year planning period, additional emissions reductions will be required to continue to demonstrate reasonable progress in each area during that period. For power plants, the Clean Air Visibility Rule allows states to determine that CAIR satisfies BART requirements for SO₂ and NO_x. Extensive studies were performed for each of the Company’s affected units to demonstrate that additional particulate matter controls are not necessary under BART. The states of Alabama and Mississippi have determined that no additional SO₂ controls beyond CAIR are needed to satisfy reasonable progress. At the request of the State of Georgia, additional analyses were performed for certain units in Georgia to demonstrate that no additional SO₂ controls were required to demonstrate reasonable progress. States have completed or are currently completing implementation plans that contain strategies for BART and any other measures required to achieve the first phase of reasonable progress.

The impacts of the eight-hour ozone nonattainment designations, the fine particulate matter nonattainment designations, and the Clean Air Visibility Rule on the Company cannot be determined at this time and will depend on the resolution of any pending legal challenges and the development and implementation of rules at the state level. For example, the State of Georgia has approved a “multi-pollutant rule” that requires plant-specific emission controls on all but the smallest generating units in Georgia to be installed according to a schedule set forth in the rule. The rule is designed to ensure reductions in emissions of SO₂, NO_x, and mercury in Georgia.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂and NO_x emission controls within the next several years to ensure continued compliance with applicable air quality requirements.

In March 2005, the EPA published the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The final Clean Air Mercury Rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners alleged that the EPA was not authorized to establish a cap-and-trade program for mercury emissions and instead the EPA must establish maximum achievable control technology standards for coal-fired electric utility steam generating units. On February 8, 2008, the court ruled in favor of the petitioners and vacated the Clean Air Mercury Rule. The Company’s overall environmental compliance strategy relies primarily on a combination of SO₂ and NOx controls to reduce mercury emissions. Any significant changes in the strategy will depend on the outcome of any appeals and/or future federal and state rulemakings. Future rulemakings necessitated by the court’s decision could require emission reductions more stringent than those required by the Clean Air Mercury Rule.

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Water Quality

In July 2004, the EPA published its final technology-based regulations under the Clean Water Act for the purpose of reducing impingement and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling water intake structures. The rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants. In January 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule, including the use of cost-benefit analysis, to the EPA for revisions. The decision has been appealed to the U.S. Supreme Court. The full impact of these regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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.

Global Climate Issues

Federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions and renewable energy standards continue to be strongly considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. The ultimate outcome of these proposals cannot be determined at this time; however, mandatory restrictions on the Company’s greenhouse gas emissions 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.

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. The EPA is currently developing its response to this decision. Regulatory decisions that will follow from this response may have implications for both new and existing stationary sources, such as power plants. The ultimate outcome of these rulemaking activities cannot be determined at this time; however, as with the current legislative proposals, mandatory restrictions on the Company’s greenhouse gas emissions 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.

In addition, some states are considering or have undertaken actions to regulate and reduce greenhouse gas emissions. For example, on June 25, 2008, Florida’s Governor signed comprehensive energy-related legislation that includes authorization for the Florida Department of Environmental Protection to adopt rules for a cap-and-trade regulatory program to address greenhouse gas emissions from electric utilities, conditioned upon their ratification by the legislature no sooner than the 2010 legislative session. This legislation also authorizes the Florida PSC to adopt a renewable portfolio standard for public utilities, subject to legislative ratification. The impact of this and any similar legislation on Southern Company will depend on the future development, adoption, legislative ratification,

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implementation, and potential legal challenges to rules governing greenhouse gas emissions and mandates regarding the use of renewable energy, and the ultimate outcome cannot be determined at this time.

International climate change negotiations under the United Nations Framework Convention on Climate Change also continue. Current efforts focus on a potential successor to the Kyoto Protocol for the post 2012 timeframe, with a conclusion to this round of negotiations targeted for the end of 2009. The outcome and impact of the international negotiations cannot be determined at this time.

The Company is actively evaluating and developing electric generating technologies with lower greenhouse gas emissions. These include new nuclear generation, including proposed construction of two additional generating units at Plant Vogtle in Georgia; proposed construction of an advanced IGCC unit with approximately 50% carbon capture in Kemper County, Mississippi; and renewables investments, including the proposed conversion of Plant Mitchell in Georgia from coal-fired to biomass generation. The Company is currently considering additional projects and is pursuing research into the costs and viability of other renewable technologies for the Southeast.

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 dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by 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 be subject to refund to a cost-based rate level.

In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates, and could also result in total refunds of up to $19.7 million, plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for an adverse decision in this proceeding and are vigorously defending themselves in this matter.

In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008 and Order No. 697-B on December 12, 2008. These orders largely affirmed the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis on September 2, 2008 related to its continued market-based rate authority. The ultimate outcome of this matter cannot now be determined.

On October 17, 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability

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obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On December 18, 2008, the FERC issued an order conditionally accepting the MBR tariff subject to certain revisions to the auction proposal. On January 21, 2009, Southern Company made a compliance filing that accepted all the conditions of the MBR tariff order. When this order becomes final, Southern Company will have 30 days to implement the wholesale auction. On December 31, 2008, the FERC issued an order conditionally accepting the CBR tariff subject to providing additional information concerning one aspect of the tariff. On January 30, 2009, Southern Company filed a response addressing the FERC inquiry to the CBR tariff order. Implementation of the energy auction in accordance with the MBR tariff order is expected to adequately mitigate going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory. The timing of when the FERC may issue the final orders on the MBR and CBR tariffs and the ultimate outcome of these matters cannot be determined at this time.

Generation Interconnection Agreements

In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities. No other similar complaints are pending with the FERC.

In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and Southern Company and Tenaska have appealed the orders to the U.S. Circuit Court for the District of Columbia. The final outcome of this matter cannot now be determined.

PSC Matters

Alabama Power

Effective January 2007 and thereafter, Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail 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 13.0% 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 October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual revenues of approximately $168 million. Alabama Power agreed to a moratorium on any increase in 2009 under Rate RSE. Alabama Power also agreed to defer any increase in rates during 2009 under the portion of Rate Certificated New Plant which permits recovery of costs associated with environmental laws and regulations until 2010. The deferral of the retail rate adjustments will have no significant effect on Southern Company’s revenues or net income, but will have an immaterial impact on annual cash flows. On December 1, 2008, Alabama Power made its submission of projected data for calendar year 2009. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information.

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Southern Company and Subsidiary Companies 2008 Annual Report

Georgia Power

In December 2007, the Georgia PSC approved the retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan). Under the 2007 Retail Rate Plan, Georgia Power’s earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an environmental compliance cost recovery (ECCR) tariff. Georgia Power has agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by approximately $99.7 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 for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. 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 “Georgia Power Retail Regulatory Matters” for additional information.

Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have continued to experience higher than expected fuel costs for coal, natural gas, and uranium. The traditional operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. Each of the traditional operating companies received approval in 2007 and/or 2008 to increase its fuel cost recovery factor to recover existing under recovered amounts as well as projected future costs. At December 31, 2008, the amount of under recovered fuel costs included in the balance sheets was $1.2 billion compared to $1.1 billion at December 31, 2007.

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. Based on their respective state PSC orders, a portion of the under recovered regulatory clause revenues for Alabama Power and Georgia Power was reclassified from current assets to deferred charges and other assets in the balance sheets. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters”, “Georgia Power Retail Regulatory Matters”, and “Gulf Power Retail Regulatory Matters” for additional information.

Storm Damage Cost Recovery

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 addition, each of the traditional operating companies has been authorized by its state PSC to defer the portion of the major storm restoration costs that exceeded the balance in its storm damage reserve account. As of December 31, 2008, the under recovered balance in Southern Company’s storm damage reserve accounts totaled approximately $27 million, of which approximately $21 million and $6 million, respectively, are included in the balance sheets herein under “Other Current Assets” and “Other Regulatory Assets.”

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

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Mississippi Base Load Construction Legislation

In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the Governor on May 9, 2008 to enhance the Mississippi PSC’s authority to facilitate development and construction of base load generation in the State of Mississippi (Baseload Act). The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. The effect of this legislation on Southern Company cannot now be determined.

Mirant Matters

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 for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant). Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 to the financial statements under “Guarantees” and with various lawsuits discussed in Note 3 to the financial statements under “Mirant Matters.”

In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Through December 2008, Southern Company received from the IRS approximately $38 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, a special purpose subsidiary of Reorganized Mirant, has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company has reserved the remaining amount with respect to its Mirant tax claim.

If Southern Company is ultimately required to make any additional payments either with respect to the IRS audit or its contingent obligations under guarantees of Mirant subsidiaries, Mirant’s indemnification obligation to Southern Company for these additional payments, if allowed, would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant. See Note 3 to the financial statements under “Mirant Matters — Mirant Bankruptcy.”

In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007. In January 2006, MC Asset Recovery was substituted as plaintiff. The fourth amended complaint (the complaint) alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company

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prior to the spin-off. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also seeks recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleged a claim under the Federal Debt Collection Procedure Act (FDCPA) to avoid certain transfers from Mirant to Southern Company; however, on July 7, 2008, the court ruled that the FDCPA does not apply and that Georgia law should apply instead. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint includes an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.

In February 2006, the Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts in the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint were barred; all other claims were allowed to proceed. On August 6, 2008, Southern Company filed a second motion for summary judgment. MC Asset Recovery filed its response to Southern Company’s motion for summary judgment on October 20, 2008. On February 5, 2009, the court denied the summary judgment motion in connection with the fraudulent conveyance and illegal dividend claims concerning certain advance return/loan repayments in 1999, dividends in 1999 and 2000, and transfers in connection with Mirant’s separation from Southern Company. The court granted Southern Company’s motion for summary judgment with respect to certain claims, including claims for restitution and unjust enrichment, claims that Southern Company aided and abetted Mirant’s directors’ breach of fiduciary duties to Mirant, and claims that Southern Company used Mirant as an alter ego. In addition, the court granted Southern Company’s motion in connection with the fraudulent transfer and illegal dividend claims concerning certain turbine termination payments. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. See Note 3 to the financial statements under “Mirant Matters — MC Asset Recovery Litigation” for additional information. The ultimate outcome of these matters cannot be determined at this time.

Mirant Securities Litigation

In November 2002, Southern Company, certain former and current senior officers of Southern Company, and 12 underwriters of Mirant’s initial public offering were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. Several other similar lawsuits filed subsequently were consolidated into this litigation in the U.S. District Court for the Northern District of Georgia. The amended complaint is based on allegations related to alleged improper energy trading and marketing activities involving the California energy market, alleged false statements and omissions in Mirant’s prospectus for its initial public offering and in subsequent public statements by Mirant, and accounting-related issues previously disclosed by Mirant. The lawsuit purports to include persons who acquired Mirant securities between September 26, 2000 and September 5, 2002.

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as to Mirant prior to the spin-off date. Southern Company filed an answer to the consolidated amended class action complaint in September 2003. Plaintiffs also filed a motion for class certification.

During Mirant’s Chapter 11 proceeding, the securities litigation was stayed, with the exception of limited discovery. Since Mirant’s plan of reorganization has become effective, the stay has been lifted. In March 2006, the plaintiffs filed a motion for reconsideration requesting that the court vacate that portion of its July 2003 order dismissing the plaintiffs’ claims based upon Mirant’s alleged improper energy trading and marketing activities involving the California energy market. Southern Company and the other defendants opposed the plaintiffs’ motion. In March 2007, the court granted plaintiffs’ motion for reconsideration, reinstated the California energy market claims, and granted in part and denied in part defendants’ motion to compel certain class certification discovery. In March 2007, defendants filed renewed motions to dismiss the California energy claims on grounds originally set forth in their 2003 motions to dismiss, but which were not addressed by the court. In July 2007, certain defendants, including Southern Company, filed motions for reconsideration of the court’s denial of a motion seeking dismissal of certain federal securities laws claims based upon, among other things, certain alleged errors included in financial statements issued by Mirant. On August 6, 2008, the court entered an order in regard to the defendants’ motions to dismiss and for partial summary judgment. The court granted the defendants’ motion for partial summary judgment in two respects concluding that certain holders of Mirant stock do not have standing under the securities laws. The court denied the defendants’ other motions and granted leave to the plaintiffs to re-plead their claims against the defendants. In accordance with the court’s order, the plaintiffs filed an amended complaint. The plaintiffs added allegations based upon claims asserted against Southern Company in the MC Asset Recovery litigation. Southern Company and the remaining defendants filed motions to dismiss the amended complaint on October 9, 2008. On January 7, 2009, the trial judge dismissed all counts of the plaintiffs’ second amended complaint with prejudice. This matter is now concluded.

Income Tax Matters

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. These incentives could have a significant impact on Southern Company’s future cash flow and net income. Additionally, the ARRA includes programs for renewable energy, transmission and smart grid enhancement, fossil energy and research, and energy efficiency and conservation. The ultimate impact cannot be determined at this time.

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. 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

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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 years 2007 through 2009, and a 9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company has agreed with the IRS on a calculation methodology and signed a closing agreement on December 11, 2008. Therefore, Southern Company reversed the unrecognized tax benefit and adjusted the deduction to conform to the agreement. 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. See Note 5 to the financial statements under “Effective Tax Rate” for additional information.

Construction Projects

Integrated Coal Gasification Combined Cycle

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 coal IGCC with an output capacity of 582 megawatts. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in November 2013. As part of its filing, Mississippi Power has requested certain rate recovery treatment in accordance with the base load construction legislation. See FUTURE EARNINGS POTENTIAL — “PSC Matters – Mississippi Base Load Construction Legislation” herein for additional information.

Mississippi Power filed an application in June 2006 with the U.S. Department of Energy (DOE) for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the Kemper IGCC, and in November 2006 the IRS allocated Internal Revenue Code Section 48A tax credits of $133 million to Mississippi Power. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than November 2013. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for the Section 48A credits.

On February 14, 2008, Mississippi Power also requested that the DOE transfer the remaining funds previously granted to a cancelled Southern Company project that would have been located in Orlando, Florida. On December 12, 2008, an agreement was reached to assign the remaining funds to the Kemper IGCC. The estimated construction cost of the Kemper IGCC is approximately $2.2 billion, which is net of $220 million related to funding to be received from the DOE related to project construction. The remaining DOE funding of $50 million is projected to be used for demonstration over the first few years of operation.

Beginning in December 2006, the Mississippi PSC has approved Mississippi Power’s requested accounting treatment to defer the costs associated with Mississippi Power’s generation resource planning, evaluation, and screening activities as a regulatory asset. On December 22, 2008, Mississippi Power requested an amendment to its original order that would allow these costs to continue to be charged to and remain in a regulatory asset until January 1, 2010. In its application, Mississippi Power reported that it anticipated spending approximately $61 million by or before May 31, 2009. At December 31, 2008, Mississippi Power had spent $42.3 million of the $61 million, of which $3.7 million related to land purchases capitalized. Of the remaining amount, $0.8 million was expensed and $37.8 million was deferred in other regulatory assets.

The final outcome of this matter cannot now be determined.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Nuclear

In August 2006, Southern Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, Owners), filed an application with the Nuclear Regulatory Commission (NRC) for an early site permit relating to two additional nuclear units on the site of Plant Vogtle. See Note 4 to the financial statements for additional information on these co-owners. On March 31, 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units.

On April 8, 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners will pay a purchase price that will be subject to certain price escalation and adjustments, adjustments for change orders, and performance bonuses. 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, based on its current ownership interest, is 45.7%. Under the terms of a separate joint development agreement, the Owners finalized their ownership percentages on July 2, 2008, except for allowed changes, under certain limited circumstances, during the Georgia PSC certification process.

On August 1, 2008, Georgia Power submitted an application for the Georgia PSC to certify the project. Hearings began November 3, 2008 and a final certification decision is expected in March 2009.

If certified by the Georgia PSC and licensed by the NRC, Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively. The total plant value to be placed in service will also include financing costs for each of the Owners, the impacts of inflation on costs, and transmission and other costs that are the responsibility of the Owners. Georgia Power’s proportionate share of the estimated in-service costs, based on its current ownership interest, is approximately $6.4 billion, subject to adjustments and performance bonuses under the Vogtle 3 and 4 Agreement.

The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Owners and the Consortium also have agreed to certain bonuses payable to the Consortium for early completion and unit performance. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

The obligations of Westinghouse Electric Company LLC and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

In connection with the certification application, Georgia Power has requested Georgia PSC approval to include the construction work in progress accounts for Plant Vogtle Units 3 and 4 in rate base and allow Georgia Power to recover financing costs during the construction period.

On February 11, 2009, the Georgia State Senate passed Senate Bill 31 that would allow the Company to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. A similar bill is being considered in the Georgia State House of Representatives.

Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy was organized to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs. COLs for the two reactor designs were submitted to the NRC during the fourth quarter of 2007. The COLs ultimately are expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.

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

The final outcome of these matters cannot now be determined.

Nuclear Relicensing

The NRC operating licenses for Plant Vogtle Units 1 and 2 currently expire in January 2027 and February 2029, respectively. In June 2007, Georgia Power filed an application with the NRC to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. Georgia Power anticipates the NRC may make a decision regarding the license extension for Plant Vogtle in 2009.

Other Matters

Georgia Power has initiated a voluntary attrition plan under which participating employees may elect to resign from their positions as of March 31, 2009. Approximately 700 employees who have indicated an interest in participating in the plan have been selected by Georgia Power and are permitted to resign and receive severance. Each participating employee who resigns under the plan will be entitled to receive a severance payment equal to his or her annual base salary, accrued vacation, and pro-rated bonus as of March 31, 2009. Southern Company will record a charge during the first quarter 2009 in connection with the plan. The ultimate amount of the charge will be dependent on the total number of employees who elect to resign under the plan. Such charge could have a material impact on Southern Company’s statements of income for the quarter ending March 31, 2009 and statements of cash flow for the six months ending June 30, 2009. The first quarter 2009 charge will generally be offset with lower salary costs for the remainder of the year and is not expected to have a material impact on Southern Company’s financial statements for the year ending December 31, 2009.

Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements. See Note 3 to the financial statements for information regarding material issues.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Electric Utility Regulation

Southern Company’s traditional operating companies, which comprised approximately 95% of Southern Company’s total operating revenues for 2008, 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 FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of SFAS No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the 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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

accordance with generally accepted accounting principles, 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, 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, the FERC, or the EPA.

Unbilled Revenues

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

New Accounting Standards

Business Combinations

In December 2007, the FASB issued FASB Statement No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). Southern Company adopted SFAS No. 141R on January 1, 2009. The adoption of SFAS No. 141R could have an impact on the accounting for any business combinations completed by Southern Company after January 1, 2009.

In December 2007, the FASB issued FASB Statement No. 160, “Non-controlling Interests in Consolidated Financial Statements” (SFAS No. 160). SFAS No. 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the non-controlling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary should be reported as equity in the consolidated financial statements and establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Southern Company adopted SFAS No. 160 on January 1, 2009 with no material impact to the financial statements.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at December 31, 2008. Throughout the recent 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 and the traditional operating companies have continued to issue commercial paper at reasonable rates. 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. No material changes in bank credit arrangements have occurred although market rates for committed credit have increased and the Company may be subject to higher costs as its existing facilities are replaced or renewed. Southern Company’s interest cost for short-term debt has decreased as market short-term interest rates have declined. The ultimate impact on future financing costs as a result of the financial turmoil cannot be determined at this time. Southern Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Southern Company’s investments in pension and nuclear decommissioning trust funds declined in value as of December 31, 2008. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts at this time.

Net cash provided from operating activities in 2008 totaled $3.4 billion, an increase of $3 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 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 $575 million as compared to 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. In 2006, net cash provided from operating activities totaled $2.8 billion, an increase over the previous year of $290 million, primarily as a result of a decrease in under recovered storm restoration costs, a decrease in accounts payable from year-end 2005 amounts that included substantial hurricane-related expenditures, partially offset by an increase in fossil fuel inventory.

Net cash used for investing activities in 2008 totaled $4.1 billion primarily due to property additions to utility plant of $4.0 billion. Net cash used for investing activities in 2007 totaled $3.7 billion primarily due to property additions to utility plant of $3.5 billion. In 2006, net cash used for investing activities was $2.8 billion primarily due to property additions to utility plant of $3.0 billion, partially offset by proceeds from the sale of Southern Company Gas LLC and the receipt by Mississippi Power of capital grant proceeds related to Hurricane Katrina.

Net cash provided from financing activities totaled $944 million in 2008 primarily due to long-term debt issuances. Net cash provided from financing activities totaled $348 million in 2007 primarily due to replacement of short-term debt with longer term financing and cash raised from common stock programs. In 2006, net cash used for financing activities was $21 million.

Significant balance sheet changes in 2008 include an increase in total property, plant, and equipment of $2.5 billion and an increase in long-term debt, excluding amounts due within one year, of $2.7 billion used primarily for construction expenditures and general corporate purposes. Other significant balance sheet changes which are

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

primarily attributable to the decline in market value of the Company’s pension trust fund include a decrease of $2.4 billion in prepaid pension costs, an increase of $1.9 billion in other regulatory assets, and a decrease of $1.3 billion in other regulatory liabilities.

At the end of 2008, the closing price of Southern Company’s common stock was $37.00 per share, compared with book value of $17.08 per share. The market-to-book value ratio was 217% at the end of 2008, compared with 239% at year-end 2007.

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. SCS has an investment grade corporate credit rating.

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 2009, 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. The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. In addition, the issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power 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, 2008, Southern Company and its subsidiaries had approximately $417 million of cash and cash equivalents and $4.2 billion of unused credit arrangements with banks, of which $970 million expire in 2009, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $84 million of the credit facilities expiring in 2009 allow for the execution of term loans for an additional two-year period, and $544 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Financing Activities

During 2008, Southern Company and its subsidiaries issued $2.5 billion of senior notes and $566 million of obligations related to pollution control revenue bonds. In addition, Georgia Power, Gulf Power, and Mississippi Power entered into long-term bank loans of $300 million, $110 million, and $80 million, respectively. Georgia Power and Gulf Power also entered into short-term bank loans of $100 million and $50 million, respectively. Interest rate hedges of $405 million notional amount were settled at a loss of $26 million related to the issuances. Southern Company issued $474 million of common stock through the Southern Company Investment Plan and employee and director stock plans. The security issuances were used to redeem or repay at maturity $1.5 billion of long-term debt, to reduce short-term indebtedness, to fund Southern Company’s ongoing construction program, and for general corporate purposes. Additionally, interest rate hedges of $100 million were settled early at a loss of $2 million related to counterparty credit issues.

Also in 2008, the traditional operating companies converted their entire $1.2 billion of obligations related to auction rate pollution control revenue bonds from auction rate modes to other interest rate modes. Initially, approximately $696 million of the auction rate pollution control revenue bonds were converted to fixed interest rate modes and approximately $553 million were converted to variable rate modes. In June 2008, approximately $98 million of the variable rate pollution control revenue bonds were converted to fixed interest rate modes.

During the third quarter 2008, Alabama Power, Georgia Power, and Mississippi Power were required to purchase a total of approximately $96 million of variable rate pollution control revenue bonds that were tendered by investors. Alabama Power and Mississippi Power remarketed all of their repurchased variable rate pollution control revenue bonds of $11 million and $8 million, respectively. Georgia Power remarketed $75 million of its $77 million of tendered bonds. The remaining $2 million were extinguished.

In the fourth quarter 2008, Georgia Power and Gulf Power converted a total of approximately $171 million of variable rate pollution control revenue bonds to fixed interest rate modes.

Subsequent to December 31, 2008, Georgia Power issued $500 million of Series 2009A 5.95% Senior Notes due February 1, 2039. The proceeds were used to repay $150 million of its Series U Floating Rate Senior Notes at maturity, to repay short-term indebtedness, and for other general corporate purposes. Georgia Power settled $100 million of hedges related to the issuance at a loss of approximately $16 million.

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. See Note 7 to the financial statements under “Operating Leases” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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. At December 31, 2008, 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 $395 million. At December 31, 2008, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.8 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the Company’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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, 2008 have a notional amount of $1.4 billion and are related to anticipated debt issuances and various floating rate obligations over the next two years. The weighted average interest rate on $1.6 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2009 was 2.45%. 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 $16 million at January 1, 2009. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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


	2008			2007
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	4		$	(82	)
Contracts realized or settled		(150	)		80
Current period changes^(a)		(139	)		6

Contracts outstanding at the end of the period, assets (liabilities), net	$	(285	)	$	4

(a)

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

The decrease in the fair value positions of the energy-related derivative contracts for the year-ended December 31, 2008 was $289 million, substantially all of which is due to natural gas positions. This change is attributable to both the volume and prices of natural gas. At December 31, 2008, Southern Company had a net hedge volume of 148.9 billion cubic feet (Bcf) with a weighted average contract cost approximately $1.97 per million British thermal units (mmBtu) above market prices, compared to 99.0 Bcf at December 31, 2007 with a weighted average contract cost approximately $0.01 per mmBtu above market prices. The majority of the natural gas hedges are recorded through the traditional operating companies’ fuel cost recovery clauses.

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:


	2008			2007
	(in millions)
Regulatory hedges	$	(288	)	$	—
Cash flow hedges		(1	)		1
Non-accounting hedges		4			3

Total fair value	$	(285	)	$	4

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.

Unrealized pre-tax gains/(losses) recognized in income for energy-related derivative contracts that are not hedges were not material for any year presented.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at December 31, 2008 are as follows:


	December 31, 2008
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(285	)		(203	)		(77	)		(5	)
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(285	)	$	(203	)	$	(77	)	$	(5	)

As part of the adoption of FASB Statement No. 157, “Fair Value Measurements” to increase consistency and comparability in fair value measurements and related disclosures, the table above now uses the three-tier fair value hierarchy, as discussed in Note 10 to the financial statements, as opposed to the previously used descriptions “actively quoted,” “external sources,” and “models and other methods.” The three-tier fair value hierarchy focuses on the fair value of the contract itself, whereas the previous descriptions focused on the source of the inputs. Because Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, the valuations of those contracts now appear in Level 2; previously they were shown as “actively quoted.”

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

During 2006 and 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 year ended December 31, 2008. For 2007 and 2006, the fair value gain/(loss) recognized in other income/(expense) to mark the transactions to market was $27 million and $(32) million, respectively. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of Southern Company is currently estimated to be $5.7 billion for 2009, $5.1 billion for 2010, and $5.8 billion for 2011. These estimates include costs for new generation construction. Environmental expenditures included in these estimated amounts are $1.4 billion, $737 million, and $871 million for 2009, 2010, and 2011, 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; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

C-38

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 and preferred securities, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

C-39

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Contractual Obligations


			2010-		2012-		After		Uncertain
	2009		2011		2013		2013		Timing^(d)		Total
	(in millions)
Long-term debt^(a) —
Principal	$	617	$	1,972	$	2,745	$	12,119	$	—	$	17,453
Interest		858		1,616		1,424		11,102		—		15,000
Preferred and preference stock dividends^(b)		65		130		130		—		—		325
Other derivative obligations^(c) —
Energy-related		224		78		5		—		—		307
Interest		21		—		—		—		—		21
Operating leases		143		212		81		146		—		582
Unrecognized tax benefits and interest^(d)		145		—		—		—		16		161
Purchase commitments^(e) —
Capital^(f)		5,467		10,644		—		—		—		16,111
Limestone^(g)		13		70		72		144		—		299
Coal		4,608		5,999		2,602		3,421		—		16,630
Nuclear fuel		187		301		275		43		—		806
Natural gas^(h)		1,507		1,609		1,242		3,798		—		8,156
Purchased power		217		455		413		1,938		—		3,023
Long-term service agreements⁽ⁱ⁾		85		203		255		1,731		—		2,274
Trusts —
Nuclear decommissioning		3		7		7		53		—		70
Postretirement benefits^(j)		56		116		—		—		—		172

Total	$	14,216	$	23,412	$	9,251	$	34,495	$	16	$	81,390


(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, 2009, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

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

(c)		For additional information, see Notes 1 and 6 to the financial statements.

(d)		The timing related to the $16 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 2008, 2007, and 2006 were $3.8 billion, $3.7 billion, and $3.5 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, 2008, 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 begun construction of flue gas desulfurization projects and have entered into various long-term commitments for the procurement of limestone to be used in such 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, 2008.

(i)		Long-term service agreements include price escalation based on inflation indices.

(j)		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 2011 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. 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-40

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2008 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales growth, customer growth, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, earnings growth, dividend payout ratios, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, unrecognized tax benefits related to leveraged lease transactions, 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, or particulate matter 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, 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;

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

•		advances in technology;

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

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

•		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 neighboring utilities and other 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 an avian influenza, or other similar occurrences;

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

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

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

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

C-41

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2008, 2007, and 2006

Southern Company and Subsidiary Companies 2008 Annual Report



	2008			2007			2006
	(in millions)

Operating Revenues:
Retail revenues	$	14,055		$	12,639		$	11,801
Wholesale revenues		2,400			1,988			1,822
Other electric revenues		545			513			465
Other revenues		127			213			268

Total operating revenues		17,127			15,353			14,356

Operating Expenses:
Fuel		6,818			5,856			5,152
Purchased power		815			515			543
Other operations and maintenance		3,748			3,670			3,519
Depreciation and amortization		1,443			1,245			1,200
Taxes other than income taxes		797			741			718

Total operating expenses		13,621			12,027			11,132

Operating Income		3,506			3,326			3,224
Other Income and (Expense):
Allowance for equity funds used during construction		152			106			50
Interest income		33			45			41
Equity in income (losses) of unconsolidated subsidiaries		11			(24	)		(57	)
Leveraged lease (losses) income		(85	)		40			69
Impairment loss on equity method investments		—			—			(16	)
Interest expense, net of amounts capitalized		(866	)		(886	)		(866	)
Preferred and preference dividends of subsidiaries		(65	)		(48	)		(34	)
Other income (expense), net		(29	)		10			(58	)

Total other income and (expense)		(849	)		(757	)		(871	)

Earnings Before Income Taxes		2,657			2,569			2,353
Income taxes		915			835			780

Consolidated Net Income	$	1,742		$	1,734		$	1,573

Common Stock Data:
Earnings per share—
Basic	$	2.26		$	2.29		$	2.12
Diluted		2.25			2.28			2.10

Average number of shares of common stock outstanding — (in millions)
Basic		771			756			743
Diluted		775			761			748

Cash dividends paid per share of common stock	$	1.6625		$	1.595		$	1.535

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

C-42

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2008, 2007, and 2006

Southern Company and Subsidiary Companies 2008 Annual Report



	2008			2007			2006
	(in millions)
Operating Activities:
Consolidated net income	$	1,742		$	1,734		$	1,573
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization		1,704			1,486			1,421
Deferred income taxes and investment tax credits		215			7			202
Deferred revenues		120			(2	)		(1	)
Allowance for equity funds used during construction		(152	)		(106	)		(50	)
Equity in (income) losses of unconsolidated subsidiaries		(11	)		24			57
Leveraged lease losses (income)		85			(40	)		(69	)
Pension, postretirement, and other employee benefits		21			39			46
Stock based compensation expense		20			28			28
Derivative fair value adjustments		(1	)		(30	)		32
Hedge settlements		15			10			13
Hurricane Katrina grant proceeds-property reserve		—			60			—
Other, net		(97	)		60			51
Changes in certain current assets and liabilities —
Receivables		(176	)		165			(69	)
Fossil fuel stock		(303	)		(39	)		(246	)
Materials and supplies		(23	)		(71	)		7
Other current assets		(36	)		—			73
Accounts payable		(74	)		105			(173	)
Hurricane Katrina grant proceeds		—			14			120
Accrued taxes		293			(19	)		(103	)
Accrued compensation		36			(40	)		(24	)
Other current liabilities		20			10			(68	)

Net cash provided from operating activities		3,398			3,395			2,820

Investing Activities:
Property additions		(3,961	)		(3,545	)		(2,994	)
Investment in restricted cash from pollution control bonds		(96	)		(157	)		—
Distribution of restricted cash from pollution control bonds		69			78			—
Nuclear decommissioning trust fund purchases		(720	)		(783	)		(751	)
Nuclear decommissioning trust fund sales		712			775			743
Proceeds from property sales		34			33			150
Hurricane Katrina capital grant proceeds		7			35			153
Investment in unconsolidated subsidiaries		(1	)		(37	)		(64	)
Cost of removal net of salvage		(123	)		(108	)		(90	)
Other		(47	)		—			19

Net cash used for investing activities		(4,126	)		(3,709	)		(2,834	)

Financing Activities:
Increase (decrease) in notes payable, net		(314	)		(669	)		683
Proceeds —
Long-term debt		3,686			3,826			1,564
Preferred and preference stock		—			470			150
Common stock		474			538			137
Redemptions —
Long-term debt		(1,469	)		(2,566	)		(1,366	)
Preferred and preference stock		(125	)		—			(15	)
Payment of common stock dividends		(1,280	)		(1,205	)		(1,140	)
Other		(28	)		(46	)		(34	)

Net cash provided from (used for) financing activities		944			348			(21	)

Net Change in Cash and Cash Equivalents		216			34			(35	)
Cash and Cash Equivalents at Beginning of Year		201			167			202

Cash and Cash Equivalents at End of Year	$	417		$	201		$	167

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

C-43

CONSOLIDATED BALANCE SHEETS

At December 31, 2008 and 2007

Southern Company and Subsidiary Companies 2008 Annual Report

Assets

2008

2007

(in millions)

Current Assets:

Cash and cash equivalents

417

201

Restricted cash

103

Receivables —

Customer accounts receivable

1,054

1,000

Unbilled revenues

320

294

Under recovered regulatory clause revenues

646

716

Other accounts and notes receivable

301

348

Accumulated provision for uncollectible accounts

(26

)

(22

)

Fossil fuel stock, at average cost

1,018

710

Materials and supplies, at average cost

757

725

Vacation pay

140

135

Prepaid expenses

302

146

Other

326

411

Total current assets

5,358

4,732

Property, Plant, and Equipment:

In service

50,618

47,176

Less accumulated depreciation

18,286

17,413

32,332

29,763

Nuclear fuel, at amortized cost

510

336

Construction work in progress

3,036

3,228

Total property, plant, and equipment

35,878

33,327

Other Property and Investments:

Nuclear decommissioning trusts, at fair value

864

1,132

Leveraged leases

897

984

Other

227

238

Total other property and investments

1,988

2,354

Deferred Charges and Other Assets:

Deferred charges related to income taxes

973

910

Prepaid pension costs

—

2,369

Unamortized debt issuance expense

208

191

Unamortized loss on reacquired debt

271

289

Deferred under recovered regulatory clause revenues

606

389

Other regulatory assets

2,637

768

Other

428

460

Total deferred charges and other assets

5,123

5,376

Total Assets

48,347

45,789

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

C-44

CONSOLIDATED BALANCE SHEETS
At December 31, 2008 and 2007
Southern Company and Subsidiary Companies 2008 Annual Report

Liabilities and Stockholders’ Equity

2008

2007

(in millions)

Current Liabilities:

Securities due within one year

617

1,178

Notes payable

953

1,272

Accounts payable

1,250

1,214

Customer deposits

302

274

Accrued taxes —

Income taxes

197

Unrecognized tax benefits

131

165

Other

396

330

Accrued interest

196

218

Accrued vacation pay

179

171

Accrued compensation

447

408

Liabilities from risk management activities

261

Other

297

286

Total current liabilities

5,226

5,631

Long-term Debt (See accompanying statements)

16,816

14,143

Deferred Credits and Other Liabilities:

Accumulated deferred income taxes

6,080

5,839

Deferred credits related to income taxes

259

272

Accumulated deferred investment tax credits

455

479

Employee benefit obligations

2,057

1,492

Asset retirement obligations

1,183

1,200

Other cost of removal obligations

1,321

1,308

Other regulatory liabilities

262

1,613

Other

330

347

Total deferred credits and other liabilities

11,947

12,550

Total Liabilities

33,989

32,324

Preferred and Preference Stock of Subsidiaries (See accompanying statements)

1,082

1,080

Common Stockholders’ Equity (See accompanying statements)

13,276

12,385

Total Liabilities and Stockholders’ Equity

48,347

45,789

Commitments and Contingent Matters (See notes)

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

C-45

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2008 and 2007

Southern Company and Subsidiary Companies 2008 Annual Report



		2008			2007			2008			2007
		(in millions)						(percent of total)

Long-Term Debt:
Long-term debt payable to affiliated trusts —
Maturity	Interest Rates
2042 through 2044	5.50% to 5.88%	$	412		$	412

Long-term senior notes and debt —
Maturity	Interest Rates
2008	2.54% to 7.00%		—			459
2009	4.10% to 7.00%		128			127
2010	4.70%		102			102
2011	4.00% to 5.57%		303			302
2012	4.85% to 6.25%		1,778			1,478
2013	4.35% to 6.00%		936			236
2014 through 2048	4.88% to 8.20%		8,437			7,824
Adjustable rates (at 1/1/09):
2008	4.94% to 5.00%		—			550
2009	2.3288% to 2.36%		440			440
2010	2.42% to 6.10%		1,034			202
2011	1.645% to 2.35%		490			—

Total long-term senior notes and debt			13,648			11,720

Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
2016 through 2048	1.95% to 6.00%		2,030			812
Variable rates (at 1/1/09):
2011 through 2041	0.80% to 3.00%		1,257			2,170

Total other long-term debt			3,287			2,982

Capitalized lease obligations			106			101

Unamortized debt premium (discount), net			(20	)		(19	)

Total long-term debt (annual interest requirement — $858 million)			17,433			15,196
Less amount due within one year			617			1,053

Long-term debt excluding amount due within one year			16,816			14,143			53.9	%		51.2	%

C-46

CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2008 and 2007
Southern Company and Subsidiary Companies 2008 Annual Report

2008

2007

2008

2007

(in millions)

(percent of total)

Preferred and Preference Stock of Subsidiaries:

Cumulative preferred stock

$100 par or stated value — 4.20% to 5.44%

Authorized — 20 million shares

Outstanding — 1 million shares

$1 par value — 4.95% to 5.83%

Authorized — 28 million shares

Outstanding — 12 million shares: $25 stated value

294

294

Outstanding — 2008: 0 shares

—

123

Outstanding — 2007: 1,250 shares: $100,000 stated capital

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 — $65 million)

1,082

1,205

Less amount due within one year

—

125

Preferred and preference stock of subsidiaries excluding amount due within one year

1,082

1,080

3.5

3.9

Common Stockholders’ Equity:

Common stock, par value $5 per share —

3,888

3,817

Authorized — 1 billion shares

Issued — 2008: 778 million shares

— 2007: 764 million shares

Treasury — 2008: 0.4 million shares

— 2007: 0.4 million shares

Paid-in capital

1,893

1,454

Treasury, at cost

(12

)

(11

)

Retained earnings

7,612

7,155

Accumulated other comprehensive income (loss)

(105

)

(30

)

Total common stockholders’ equity

13,276

12,385

42.6

44.9

Total Capitalization

31,174

27,608

100.0

100.0

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

C-47

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2008, 2007, and 2006

Southern Company and Subsidiary Companies 2008 Annual Report



	Common Stock										Accumulated
	Par		Paid-In					Retained			Other Comprehensive
	Value		Capital		Treasury			Earnings			Income (Loss)			Total
	(in millions)
Balance at December 31, 2005	$	3,759	$	1,085	$	(359	)	$	6,332		$	(128	)	$	10,689
Net income		—		—		—			1,573			—			1,573
Other comprehensive income		—		—		—			—			19			19
Adjustment to initially apply FASB Statement No. 158, net of tax		—		—		—			—			52			52
Stock issued		—		11		168			—			—			179
Cash dividends		—		—		—			(1,140	)		—			(1,140	)
Other		—		—		(1	)		—			—			(1	)

Balance at December 31, 2006		3,759		1,096		(192	)		6,765			(57	)		11,371
Net income		—		—		—			1,734			—			1,734
Other comprehensive income		—		—		—			—			27			27
Stock issued		58		356		183			—			—			597
Adjustment to initially apply FIN 48, net of tax		—		—		—			(15	)		—			(15	)
Adjustment to initially apply FSP 13-2, net of tax		—		—		—			(125	)		—			(125	)
Cash dividends		—		—		—			(1,204	)		—			(1,204	)
Other		—		2		(2	)		—			—			—

Balance at December 31, 2007		3,817		1,454		(11	)		7,155			(30	)		12,385
Net income		—		—		—			1,742			—			1,742
Other comprehensive loss		—		—		—			—			(75	)		(75	)
Stock issued		71		438		—			—			—			509
Cash dividends		—		—		—			(1,279	)		—			(1,279	)
Other		—		1		(1	)		(6	)		—			(6	)

Balance at December 31, 2008	$	3,888	$	1,893	$	(12	)	$	7,612		$	(105	)	$	13,276

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2008, 2007, and 2006

Southern Company and Subsidiary Companies 2008 Annual Report



	2008			2007			2006
	(in millions)
Consolidated Net Income	$	1,742		$	1,734		$	1,573

Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(19), $(3), and $(5), respectively		(30	)		(5	)		(8	)
Reclassification adjustment for amounts included in net income, net of tax of $7, $6, and $-, respectively		11			9			1
Marketable securities:
Changes in fair value, net of tax of $(4), $3, and $4, respectively		(7	)		4			8
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $-, respectively		—			(1	)		—
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(32), $13, and $-, respectively		(51	)		20			—
Additional prior service costs from amendment to non-qualified pension plans, net of tax of $-, $(2), and $-, respectively		—			(2	)		—
Change in additional minimum pension liability, net of tax of $-, $-, and $10, respectively		—			—			18
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $-, respectively		2			2			—

Total other comprehensive income (loss)		(75	)		27			19

Consolidated Comprehensive Income	$	1,667		$	1,761		$	1,592

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

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NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2008 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 the subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for Southern Company’s investments in leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

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.

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.

Reclassifications

Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation. The consolidated statements of income for the prior periods presented have been modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a single line item entitled “Other operations and maintenance.” The statements of cash flows for the prior periods presented were modified within the operating activities section to present a separate line item for “Deferred revenues” previously included in “Other, net.” The consolidated balance sheet at December 31, 2007 has been modified within current liabilities to reflect the amount of “Unrecognized tax benefits” previously included within “Accrued taxes — Income taxes” and to present the amount of “Liabilities for risk management activities” previously included in “Other.” These reclassifications had no effect on total assets, net income, cash flows, or earnings per share.

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. Total fuel purchases for January 2006 through June 2006 were $354 million. 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. In connection with these services, the related revenues of approximately $62 million for January 2006 through June 2006, have been eliminated against fuel expense in the financial statements. SSI also provided additional services to AFP, as well as

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

to a related party of AFP. Revenues from these transactions totaled approximately $24 million for January 2006 through June 2006.

Subsequent to the termination of Southern Company’s membership interest in AFP, Alabama Power and Georgia Power continued to purchase an additional $6 million, $750 million, and $384 million in fuel from AFP in 2008, 2007, and 2006, respectively. SSI continued to provide fuel transportation services of $131 million in 2007 and $62 million in 2006, 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 and $21 million in 2007 and 2006, respectively. The synthetic fuel investments and related party transactions were terminated on December 31, 2007.

Regulatory Assets and Liabilities

The traditional operating companies are subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). 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:


	2008			2007			Note
	(in millions)
Deferred income tax charges	$	972		$	911			(a	)
Asset retirement obligations-asset		236			50			(a	)
Asset retirement obligations-liability		(5	)		(154	)		(a	)
Other cost of removal obligations		(1,321	)		(1,308	)		(a	)
Deferred income tax credits		(260	)		(275	)		(a	)
Loss on reacquired debt		271			289			(b	)
Vacation pay		140			135			(c	)
Under recovered regulatory clause revenues		432			371			(d	)
Building lease		48			49			(d	)
Generating plant outage costs		45			46			(d	)
Under recovered storm damage costs		27			43			(d	)
Property damage reserves		(97	)		(90	)		(d	)
Fuel hedging (realized and unrealized) losses		314			25			(d	)
Fuel hedging (realized and unrealized) gains		(10	)		(20	)		(d	)
Other assets		164			88			(d	)
Environmental remediation-asset		67			67			(d	)
Environmental remediation-liability		(19	)		(22	)		(d	)
Deferred purchased power		(156	)		(20	)		(d	)
Other liabilities		(25	)		(21	)		(d	)
Overfunded retiree benefit plans		—			(1,288	)		(e	)
Underfunded retiree benefit plans		2,068			547			(e	)

Total assets (liabilities), net	$	2,891		$	(577	)

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

(a)		Asset retirement and removal liabilities are recorded, deferred income tax assets are recovered, and deferred tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.

(b)		Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.

(c)		Recorded as earned by employees and recovered as paid, generally within one year.

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

(e)		Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

In the event that a portion of a traditional operating company’s operations is no longer subject to the provisions of SFAS No. 71, 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 “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” “Gulf Power Retail Regulatory Matters,” and “Storm Damage Cost Recovery” for additional information.

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 is required to file a new fuel case no later than March 1, 2009. On February 19, 2009, the Georgia PSC approved Georgia Power’s request to delay the filing of that case until March 13, 2009. The new rates are expected to become effective on June 1, 2009. 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 “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Gulf Power Retail Regulatory Matters” 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 emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. 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. Investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), 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 on FIN 48.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Property, Plant, and Equipment

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

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


	2008		2007
	(in millions)
Generation	$	26,154	$	23,879
Transmission		7,085		6,761
Distribution		13,856		13,134
General		2,750		2,619
Plant acquisition adjustment		43		43

Utility plant in service		49,888		46,436

IT equipment and software		240		230
Communications equipment		450		452
Other		40		58

Other plant in service		730		740

Total plant in service	$	50,618	$	47,176

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 2008, 3.0% in 2007, and 3.0% in 2006. 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 $17.9 billion and $17.0 billion at December 31, 2008 and 2007, 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 and $14 million in 2007 and 2006, respectively. See Note 3 under “Georgia Power Retail Regulatory Matters” for additional information.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify 266 megawatts of Plant Daniel units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004 and authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power amortized the related regulatory liability pursuant to the Mississippi PSC’s order as follows: $6 million in 2007 and $13 million in 2006, resulting in increases to earnings in each of those years.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from 3 to 25 years. Accumulated depreciation for other plant in service totaled $433 million and $429 million at December 31, 2008 and 2007, 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 other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations will continue to be reflected in the balance sheets as a regulatory liability.

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, 2008 was $864 million. 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 under FASB Statement No. 143 “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement 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:


	2008			2007
	(in millions)
Balance beginning of year	$	1,203		$	1,137
Liabilities incurred		4			1
Liabilities settled		(4	)		(8	)
Accretion		75			74
Cash flow revisions		(93	)		(1	)

Balance end of year	$	1,185		$	1,203

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

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as of December 31, 2008 as trading securities pursuant to FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115).

On January 1, 2008, the Company adopted FASB Statement No. 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS No. 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Southern Company elected the fair value option only for investment securities held in the Funds. The Funds are included in the balance sheets at fair value, as disclosed in Note 10.

Management elected to continue to record the Funds at fair value because management believes that fair value best represents the nature of the Funds. Management has delegated day-to-day management of the investments in the Funds to unrelated third party managers with oversight by Southern Company, Alabama Power, and Georgia Power management. The managers of the Funds 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. Because of the Company’s inability to choose to hold securities that have experienced unrealized losses until recovery of their value, all unrealized losses incurred during 2006 and 2007, prior to the adoption of SFAS No. 159, were considered other-than-temporary impairments under SFAS No. 115.

The adoption of SFAS No. 159 had no impact on the results of operations, cash flows, or financial condition of the Company. For all periods presented, all gains and losses, whether realized, unrealized, or identified as other-than-temporary, have been and will continue to be 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, 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.

At December 31, 2007, investment securities in the Funds totaled $1.1 billion consisting of equity securities of $788 million, debt securities of $312 million, and $32 million of other securities. Unrealized gains were $256 million for equity securities and $12 million for debt securities. Other-than-temporary impairments were $(28) million for equity securities and $(5) million for debt securities.

Sales of the securities held in the Funds resulted in cash proceeds of $712 million, $775 million, and $743 million, in 2008, 2007, and 2006, respectively, all of which were re-invested. For 2008, fair value reductions, including reinvested interest and dividends, was $(278) million, of which $(259) million related to securities held in the Funds at December 31, 2008. Realized gains and other-than-temporary impairment losses were $78 million and $(76) million, respectively, in 2007 and $40 million and $(30) million, respectively, in 2006. 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 respective state PSCs. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

At December 31, 2008, the accumulated provisions for decommissioning were as follows:


	Plant Farley		Plant Hatch		Plant Vogtle
	(in millions)
External trust funds	$	404	$	280	$	168
Internal reserves		26		—		—

Total	$	430	$	280	$	168

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 2006 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		2027
Completion year		2065		2061		2051

	(in millions)
Site study costs:
Radiated structures	$	1,060	$	544	$	507
Non-radiated structures		72		46		67

Total	$	1,132	$	590	$	574

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 $495 million and $334 million for Plants Hatch and Vogtle, respectively. Amounts expensed were $3 million in 2008 and $7 million annually for 2007 and 2006 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. Georgia Power filed an application with the NRC in June 2007 to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. Georgia Power anticipates the NRC may make a decision regarding the license extension for Plant Vogtle in 2009.

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 expense. 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 standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 11.2%, 8.4%, and 4.2% of net income for 2008, 2007, and 2006, respectively.

Cash payments for interest totaled $787 million, $798 million, and $875 million in 2008, 2007, and 2006, respectively, net of amounts capitalized of $71 million, $64 million, and $27 million, respectively.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 $40.4 million in 2008. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue certain additional amounts as circumstances warrant. There were no material accruals for any year presented. See Note 3 under “Storm Damage Cost Recovery” for additional information regarding these reserves and the deferral of additional costs, as well as additional rate riders or other cost recovery mechanisms which have been approved by the respective state PSCs to recover the deferred costs and accrue reserves for future storms.

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:


	2008			2007
	(in millions)
Net rentals receivable	$	492		$	494
Unearned income		(230	)		(244	)

Investment in leveraged leases		262			250
Deferred taxes from leveraged leases		(189	)		(163	)

Net investment in leveraged leases	$	73		$	87

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


	2008			2007			2006
	(in millions)
Pretax leveraged lease income	$	14		$	16		$	20
Income tax expense		(6	)		(7	)		(9	)

Net leveraged lease income	$	8		$	9		$	11

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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


	2008			2007
	(in millions)
Net rentals receivable	$	1,298		$	1,298
Unearned income		(663	)		(563	)

Investment in leveraged leases		635			735
Current taxes payable		(120	)		—
Deferred taxes from leveraged leases		(117	)		(316	)

Net investment in leveraged leases	$	398		$	419

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


	2008			2007			2006
	(in millions)
Pretax leveraged lease income (loss)	$	(99	)	$	24		$	49
Income tax benefit (expense)		35			(8	)		(17	)

Net leveraged lease income (loss)	$	(64	)	$	16		$	32

See Note 3 under “Income Tax Matters” for additional information regarding the leveraged lease transactions.

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 emission 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. Emission 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 (categorized 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 exempt from fair value accounting requirements and are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the 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

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

investments, are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 6 under “Financial Instruments” for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2008, the Company has recognized $8.5 million for the obligation to return cash collateral arising from derivative instruments, which is included in “Accounts payable” in the balance sheets.

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

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


	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2008	$	17,327	$	17,114
2007	$	15,095	$	14,931

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2). See Note 10 for all other items recognized at fair value in the financial statements.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and certain changes in pension and other post retirement benefit plans, less income taxes 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, 2007	$	(54	)	$	13		$	11		$	(30	)
Current period change		(19	)		(7	)		(49	)		(75	)

Balance at December 31, 2008	$	(73	)	$	6		$	(38	)	$	(105	)

Variable Interest Entities

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Southern Company has established certain wholly-owned trusts to issue preferred securities. See Note 6 under “Long-Term Debt Payable to Affiliated Trusts” for additional information. However, Southern Company and the 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.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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, 2009. 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, 2009, postretirement trust contributions are expected to total approximately $56 million.

The measurement date for plan assets and obligations for 2008 was December 31 while the measurement date for prior years was September 30. Pursuant to FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), Southern Company was required to change the measurement date for its defined benefit postretirement plans from September 30 to December 31 beginning with the year ended December 31, 2008. As permitted, Southern Company adopted the measurement date provisions of SFAS No. 158 effective January 1, 2008 resulting in an increase in long-term liabilities of approximately $28 million and an increase in prepaid pension costs of approximately $16 million.

Pension Plans

The total accumulated benefit obligation for the pension plans was $5.5 billion in 2008 and $5.3 billion in 2007. Changes during the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 in the projected benefit obligations and the fair value of plan assets were as follows:


	2008			2007
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	5,660		$	5,491
Service cost		182			147
Interest cost		435			324
Benefits paid		(324	)		(241	)
Plan amendments		—			50
Actuarial gain		(74	)		(111	)

Balance at end of year		5,879			5,660

Change in plan assets
Fair value of plan assets at beginning of year		7,624			6,693
Actual return (loss) on plan assets		(2,234	)		1,153
Employer contributions		27			19
Benefits paid		(324	)		(241	)

Fair value of plan assets at end of year		5,093			7,624

Funded status at end of year		(786	)		1,964
Fourth quarter contributions		—			5

(Accrued liability) prepaid pension asset	$	(786	)	$	1,969

At December 31, 2008, the projected benefit obligations for the qualified and non-qualified pension plans were $5.5 billion and $0.4 billion, respectively. All pension plan assets are related to the qualified pension plan.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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


	Target			2008			2007

Domestic equity		36	%		34	%		38	%
International equity		24			23			24
Fixed income		15			14			15
Real estate		15			19			16
Private equity		10			10			7

Total		100	%		100	%		100	%

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


	2008			2007
	(in millions)
Prepaid pension costs	$	—		$	2,369
Other regulatory assets		1,579			188
Current liabilities, other		(23	)		(21	)
Other regulatory liabilities		—			(1,288	)
Employee benefit obligations		(763	)		(379	)
Accumulated other comprehensive income		54			(26	)

Presented below are the amounts included in accumulated other comprehensive income, regulatory assets, and regulatory liabilities at December 31, 2008 and 2007 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 2009.


	Prior Service Cost		Net(Gain)Loss
	(in millions)
Balance at December 31, 2008:
Accumulated other comprehensive income	$	12	$	42
Regulatory assets		220		1,359
Regulatory liabilities		—		—

Total	$	232	$	1,401


Balance at December 31, 2007:
Accumulated other comprehensive income	$	14	$	(40	)
Regulatory assets		66		122
Regulatory liabilities		198		(1,486	)

Total	$	278	$	(1,404	)


Estimated amortization in net periodic pension cost in 2009:
Accumulated other comprehensive income	$	2	$	—
Regulatory assets		33		7
Regulatory liabilities		—		—

Total	$	35	$	7

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 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 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table:


	Accumulated Other
	Comprehensive Income			Regulatory Assets			Regulatory Liabilities
	(in millions)
Balance at December 31, 2006	$	—		$	158		$	(507	)
Net gain		(28	)		—			(753	)
Change in prior service costs		4			46			—
Reclassification adjustments:
Amortization of prior service costs		(2	)		(7	)		(28	)
Amortization of net gain		—			(9	)		—

Total reclassification adjustments		(2	)		(16	)		(28	)

Total change		(26	)		30			(781	)

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		$	—

Components of net periodic pension cost were as follows:


	2008			2007			2006
	(in millions)
Service cost	$	146		$	147		$	153
Interest cost		348			324			300
Expected return on plan assets		(525	)		(481	)		(456	)
Recognized net loss		9			10			16
Net amortization		37			35			26

Net periodic pension cost	$	15		$	35		$	39

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, 2008, estimated benefit payments were as follows:


	Benefit Payments
	(in millions)
2009	$	289
2010		304
2011		322
2012		341
2013		362
2014 to 2018		2,187

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Other Postretirement Benefits

Changes during the 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan assets were as follows:


	2008			2007
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,797		$	1,830
Service cost		36			27
Interest cost		138			107
Benefits paid		(108	)		(83	)
Actuarial gain		(139	)		(90	)
Retiree drug subsidy		9			6

Balance at end of year		1,733			1,797

Change in plan assets
Fair value of plan assets at beginning of year		820			731
Actual return (loss) on plan assets		(232	)		105
Employer contributions		142			61
Benefits paid		(99	)		(77	)

Fair value of plan assets at end of year		631			820

Funded status at end of year		(1,102	)		(977	)
Fourth quarter contributions		—			65

Accrued liability	$	(1,102	)	$	(912	)

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


	Target			2008			2007

Domestic equity		44	%		34	%		45	%
International equity		17			18			20
Fixed income		30			38			26
Real estate		5			7			6
Private equity		4			3			3

Total		100	%		100	%		100	%

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


	2008			2007
	(in millions)
Other regulatory assets	$	489		$	360
Current liabilities, other		(3	)		(3	)
Employee benefit obligations		(1,099	)		(909	)
Accumulated other comprehensive income		8			8

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Presented below are the amounts included in accumulated other comprehensive income and regulatory assets at December 31, 2008 and 2007, 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 2009.


	Prior Service		Net(Gain)		Transition
	Cost		Loss		Obligation
	(in millions)
Balance at December 31, 2008:
Accumulated other comprehensive income	$	3	$	5	$	—
Regulatory assets		88		335		66

Total	$	91	$	340	$	66

Balance at December 31, 2007:
Accumulated other comprehensive income	$	4	$	4	$	—
Regulatory assets		99		177		84

Total	$	103	$	181	$	84


Estimated amortization as net periodic postretirement benefit cost in 2009:
Accumulated other comprehensive income	$	—	$	—	$	—
Regulatory assets		9		5		15

Total	$	9	$	5	$	15

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 15-month period ended December 31, 2008 and the 12-month period ended September 30, 2007 are presented in the following table:


	Accumulated Other
	Comprehensive Income			Regulatory Assets
	(in millions)
Balance at December 31, 2006	$	14		$	539
Net gain		(6	)		(141	)
Change in prior service costs		—			—
Reclassification adjustments:
Amortization of transition obligation		—			(15	)
Amortization of prior service costs		—			(9	)
Amortization of net gain		—			(14	)

Total reclassification adjustments		—			(38	)

Total change		(6	)		(179	)

Balance at December 31, 2007		8			360
Net loss		1			166
Change in prior service costs		—			—
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

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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


	2008			2007			2006
	(in millions)
Service cost	$	28		$	27		$	30
Interest cost		111			107			98
Expected return on plan assets		(59	)		(52	)		(49	)
Net amortization		31			38			43

Net postretirement cost	$	111		$	120		$	122

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, 2008, 2007, and 2006 by approximately $35 million, $35 million, and $39 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)
2009	$	100	$	(8	)	$	92
2010		110		(10	)		100
2011		120		(11	)		109
2012		127		(13	)		114
2013		134		(14	)		120
2014 to 2018		746		(100	)		646

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 2005 for the 2006 plan year using a discount rate of 5.50%.


	2008			2007			2006

Discount		6.75	%		6.30	%		6.00	%
Annual salary increase		3.75			3.75			3.50
Long-term return on plan assets		8.50			8.50			8.50

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

An additional assumption used in measuring the APBO was a weighted average medical care cost trend rate of 9.15% for 2009, decreasing gradually to 5.50% through the year 2015 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, 2008 as follows:


	1 Percent		1 Percent
	Increase		Decrease
	(in millions)
Benefit obligation	$	122	$	126
Service and interest costs		9		7

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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. Prior to November 2006, the Company matched employee contributions at a rate of 75% up to 6% of the employee’s base salary. Total matching contributions made to the plan for 2008, 2007, and 2006 were $76 million, $73 million, and $62 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

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

Mirant Matters

Mirant Corporation (Mirant) 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.

Mirant Bankruptcy

In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization 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).

Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 under “Guarantees” and with various lawsuits related to Mirant discussed below. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Through December 2008, Southern Company received from the IRS approximately $38 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, a special purpose subsidiary of Reorganized Mirant, has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

transfer litigation against Southern Company. Southern Company has reserved the remaining amount with respect to its Mirant tax claim.

Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. As part of a complaint filed against Southern Company in June 2005 and amended thereafter, Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off. MC Asset Recovery has been substituted as plaintiff in the complaint. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. The final outcome of this matter cannot now be determined.

MC Asset Recovery Litigation

In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007.

In December 2005, the Bankruptcy Court entered an order authorizing the transfer of this proceeding, along with certain other actions, to MC Asset Recovery. Under that order, Reorganized Mirant is obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits will be distributed to, and shared equally by, certain unsecured creditors and the original equity holders. In January 2006, the U.S. District Court for the Northern District of Texas substituted MC Asset Recovery as plaintiff.

The complaint, as amended in March 2007, alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends include without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer plaintiff asserts is valued at over $200 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also seeks recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleged a claim under the Federal Debt Collection Procedure Act (FDCPA) to avoid certain transfers from Mirant to Southern Company; however, on July 7, 2008, the court ruled that the FDCPA does not apply and that Georgia law should apply instead. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint includes an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

In January 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court and, in February 2006, granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts of the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint are barred; all other claims in the complaint were allowed to proceed. On August 6, 2008, Southern Company filed a second motion for summary judgment. MC Asset Recovery filed its response to Southern Company’s motion for summary judgment on October 20, 2008. On February 5, 2009, the court denied the summary judgment motion in connection with the fraudulent conveyance and illegal dividend claims concerning certain advance return/loan repayments in 1999, dividends in 1999 and 2000, and transfers in connection with Mirant’s separation from Southern Company. The court granted Southern Company’s motion for summary judgment with respect to certain claims, including claims for restitution and unjust enrichment, claims that Southern Company aided and abetted Mirant’s directors’ breach of fiduciary duties to Mirant, and claims that Southern Company used Mirant as an alter ego. In addition, the court granted Southern Company’s motion in connection with the fraudulent transfer and illegal dividend claims concerning certain turbine termination payments. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. However, the final outcome of this matter cannot now be determined.

Mirant Securities Litigation

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

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

dismiss and for partial summary judgment. The court granted the defendants’ motion for partial summary judgment in two respects concluding that certain holders of Mirant stock do not have standing under the securities laws. The court denied the defendants’ other motions and granted leave to the plaintiffs to re-plead their claims against the defendants. In accordance with the court’s order, the plaintiffs filed an amended complaint. The plaintiffs added allegations based upon claims asserted against Southern Company in the MC Asset Recovery litigation. Southern Company and the remaining defendants filed motions to dismiss the amended complaint on October 9, 2008. On January 7, 2009, the trial judge dismissed all counts of the plaintiffs’ second amended complaint with prejudice. This matter is now concluded.

Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Carbon Dioxide Litigation

New York Case

Kivalina Case

Environmental Remediation

Southern Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the 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, 2008 was $10.1 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, will participate in negotiations with the EPA

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

to address cleanup of the site and reimbursement for the EPA’s past expenditures related to work performed at the site. The ultimate outcome of this matter 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 $66.8 million as of December 31, 2008. 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.

FERC Matters

Market-Based Rate Authority

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 and 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. On December 12, 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were submitted. A decision is now pending from the FERC.

Generation Interconnection Agreements

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Right of Way Litigation

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

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 dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Southern Company’s financial statements.

In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Telecom, Inc. (a subsidiary of SouthernLINC Wireless), were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Income Tax Matters

Leveraged Leases

In 2002, the IRS began the examination of three sale-in-lease-out (SILO) transactions entered into by Southern Company. As a result of this examination, the IRS challenged the deductions related to these transactions. Southern disagreed with the IRS’s conclusion, went through all administrative appeals, paid approximately $168 million of the additional tax, and sued the IRS for the refund of such taxes.

During the second quarter 2008, decisions in favor of the IRS were reached in several court cases involving other taxpayers with similar leveraged lease investments. Pursuant to the application of FIN 48 and FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” management is required to assess on a periodic basis, the likely outcome of the uncertain tax positions related to the SILO transactions. Based on these accounting standards and management’s review of the recent court decisions, Southern Company recorded an after-tax charge of approximately $67 million in the second quarter 2008.

On December 12, 2008, Southern Company received from the Commissioner of the IRS an invitation to participate in a global settlement initiative related to the SILO transactions. Southern Company accepted the settlement offer on January 8, 2009. Pursuant to the settlement offer, Southern Company recorded an additional after-tax charge in the fourth quarter 2008 of $16 million. Including charges recorded in the second quarter 2008, total after-tax

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charges related to settling the SILO litigation amounted to $83 million in 2008. Of the total, approximately $7 million represents interest and $76 million represents non-cash charges related to the reallocation of lease income and will be recognized in income over the remaining term of the affected leases. A final closing agreement with the IRS is expected to be completed in the first quarter 2009. At that time, Southern Company will make a cash payment to the IRS of approximately $113 million. This payment will represent $120 million related to the timing of tax benefits recognized in prior year tax returns, partially offset by $7 million in interest refunds. The settlement of the SILO issue represented a significant non-cash operating transaction due to the deposits previously paid to the IRS. This resulted in a reduction to other current assets of approximately $207 million, a reduction of approximately $168 million in accrued taxes, and a reduction of approximately $39 million in other current liabilities.

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 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.

Alabama Power Retail Regulatory Matters

Alabama Power operates under a Rate Stabilization and Equalization Plan (Rate RSE) approved by the Alabama PSC. Prior to 2007, Rate RSE provided for periodic annual adjustments based upon Alabama Power’s earned return on end-of-period retail common equity. Effective January 2007 and thereafter, 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%. Prior to January 2007, annual adjustments were limited to 3.0%. 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. The Rate RSE increase for 2008 was 3.24%, or $147 million annually and was effective in January 2008. On October 7, 2008, the Alabama PSC approved a corrective rate package primarily providing for adjustments associated with customer charges to certain existing rate structures. This package, effective in January 2009, is expected to generate additional annual revenues of approximately $168 million. Alabama Power expects these additional revenues will preclude the need for a rate adjustment under the Rate RSE in 2009 and agreed to a moratorium on any increase in 2009 under Rate RSE. On December 1, 2008, Alabama Power made its submission of projected data for calendar year 2009. The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.

The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the cost of placing new generating facilities in retail service and for the recovery of retail costs associated with certificated purchased power agreements (Rate CNP). The annual true-up adjustment effective in April 2006 increased retail rates by 0.5%, or $19 million annually. In April 2007, there was no adjustment to Rate CNP.

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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, based on forward-looking information, began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased due to environmental costs approximately 1.2% in January 2006, 0.6% in January 2007, and 2.4% in January 2008. On October 7, 2008, Alabama Power agreed to defer any increase in rates during 2009 under the portion of Rate CNP which permits recovery of costs associated with environmental laws and regulations until 2010. The deferral of the retail rate adjustments will have no significant effect on Southern Company’s revenues or net income, but will have an immaterial impact on annual cash flows. On December 1, 2008, Alabama Power made its submission of projected data for calendar year 2009.

Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In 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 for the 30-month period ending December 2009. On October 7, 2008, the Alabama PSC approved an increase in Alabama Power’s Rate ECR factor to 3.983 cents per KWH for a 24-month period beginning with October 9, 2008 billings. Thereafter, the Rate ECR factor shall be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. During the 24-month period, Alabama Power will be allowed to continue to include a carrying charge associated with the under recovered fuel costs in the fuel expense calculation. In the event the application of this increased Rate ECR factor results in an over recovered position during this period, Alabama Power will pay interest on any such over recovered balance at the same rate used to derive the carrying cost. Accordingly, this approved increase in the billing factor will have no significant effect on Southern Company’s revenues or net income, but will increase annual cash flow. As of December 31, 2008, Alabama Power had an under recovered fuel balance of approximately $306 million, of which approximately $181 million is included in deferred charges and other assets in the balance sheets.

Georgia Power Retail Regulatory Matters

In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate Plan, Georgia Power’s earnings will continue to be evaluated against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be applied to rate refunds with the remaining one-third applied to an environmental compliance cost recovery (ECCR) tariff. There were no refunds related to earnings for the year 2008. Georgia Power has agreed that it will not file for a general base rate increase during this period unless its projected retail ROE falls below 10.25%. Retail base rates increased by approximately $99.7 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 for required environmental projects mandated by state and federal regulations. The ECCR tariff increased rates by approximately $222 million effective January 1, 2008. 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.

In December 2004, the Georgia PSC approved the retail rate plan for the years 2005 through 2007 (2004 Retail Rate Plan) for Georgia Power. 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 2006 or 2007.

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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 2007 and approximately $222 million effective June 1, 2008. The Georgia PSC order also requires Georgia Power to file for a new fuel cost recovery rate no later than March 1, 2009. On February 19, 2009, the Georgia PSC approved Georgia Power’s request to delay the filing of that case until March 13, 2009. The new rates are expected to become effective on June 1, 2009. As of December 31, 2008, Georgia Power had an under recovered fuel balance of approximately $764 million, of which approximately $426 million is included in deferred charges and other assets in the balance sheets.

Gulf Power Retail Regulatory Matters

On July 29, 2008, the Florida PSC approved Gulf Power’s request to increase the fuel cost recovery factor effective with billings beginning September 2008. The remaining portion of the projected under recovered balance is expected to be recovered in 2009. On September 2, 2008, Gulf Power filed its 2009 projected fuel cost recovery filing with the Florida PSC which includes the fuel factors proposed for January 2009 through December 2009. On October 13, 2008, Gulf Power notified the Florida PSC that the updated projected fuel cost under recovery balance at year-end exceeds the 10% threshold, but no adjustment to the fuel factor was requested. On November 6, 2008, the Florida PSC approved an increase of approximately 12.9% in the fuel factor for retail customers effective with billings beginning January 2009. The fuel factors are intended to allow Gulf Power to recover its projected 2009 fuel and purchased power costs as well as the 2008 under recovered amounts in 2009. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on Southern Company’s revenues or net income, but does impact annual cash flow. As of December 31, 2008, Gulf Power had an under recovered fuel balance of approximately $97 million, which is included in current assets in the balance sheets.

Storm Damage Cost Recovery

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 addition, each traditional operating company affected by recent hurricanes has been authorized by its state PSC to defer the portion of the hurricane restoration costs that exceeded the balance in its storm damage reserve account. As of December 31, 2008, the under recovered balance in Southern Company’s storm damage reserve accounts totaled approximately $27 million, of which approximately $21 million and $6 million, respectively, are included in the balance sheets herein under “Other Current Assets” and “Other Regulatory Assets.”

In August 2005, Hurricane Katrina hit the Gulf Coast of the United States and caused significant damage within Mississippi Power’s service area. The estimated total storm restoration costs relating to Hurricane Katrina through December 31, 2007 of $302.4 million, which was net of expected insurance proceeds of approximately $77 million, without offset for the property damage reserve of $3.0 million, was affirmed by the Mississippi PSC in June 2006, and Mississippi Power was ordered to establish a regulatory asset for the retail portion. The Mississippi PSC issued an order directing Mississippi Power to file an application with the Mississippi Development Authority (MDA) for a Community Development Block Grant (CDBG). In October 2006, Mississippi Power received from the MDA a CDBG in the amount of $276.4 million, which was allocated to both the retail and wholesale jurisdictions. In the same month, the Mississippi PSC issued a financing order that authorized the issuance of system restoration bonds for the remaining $25.2 million of the retail portion of storm recovery costs not covered by the CDBG. These funds were received in June 2007. Mississippi Power affirmed the $302.4 million total storm costs incurred as of December 31, 2007. Mississippi Power plans to file with the Mississippi PSC its final accounting of the restoration cost relating to Hurricane Katrina and the storm operations center by the end of the first quarter 2009, at which time the final net retail receivable of approximately $3.2 million is expected to be recovered.

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Southern Company and Subsidiary Companies 2008 Annual Report

In July 2006, the Florida PSC issued its order approving a stipulation and settlement between Gulf Power and several consumer groups that resolved all matters relating to Gulf Power’s request for recovery of incurred costs for storm-recovery activities and the replenishment of Gulf Power’s property damage reserve. The order provided for an extension of the storm-recovery surcharge then being collected by Gulf Power for an additional 27 months, expiring in June 2009. Funds collected by Gulf Power related to the storm recovery costs associated with previous hurricanes had been fully recovered by August 31, 2008. Funds collected by Gulf Power through its storm recovery surcharge are now being credited to the property damage reserve and will continue though June 2009 when the approved surcharge ends. The Florida PSC-approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $25.1 million and $36.0 million. The Florida PSC also authorized Gulf Power to make additional accruals above the $3.5 million at Gulf Power’s discretion. Gulf Power accrued total expenses of $3.5 million in 2008, $3.5 million in 2007, and $6.5 million in 2006. According to the order, in the case of future storms, if Gulf Power incurs cumulative costs for storm-recovery activities in excess of $10 million during any calendar year, Gulf Power will be permitted to file a streamlined formal request for an interim surcharge. Any interim surcharge would provide for the recovery, subject to refund, of up to 80% of the claimed costs for storm-recovery activities. Gulf Power would then petition the Florida PSC for full recovery through an additional surcharge or other cost recovery mechanism. As of December 31, 2008, Gulf Power’s balance in the property damage reserve totaled approximately $9.8 million which is included in the balance sheets under deferred liabilities.

Integrated Coal Gasification Combined Cycle

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 (IGCC) with an output capacity of 582 megawatts. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state environmental reviews and certain regulatory approvals, is expected to begin commercial operation in November 2013. As part of its filing, Mississippi Power has requested certain rate recovery treatment in accordance with the base load construction legislation.

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Southern Company and Subsidiary Companies 2008 Annual Report

million by or before May 31, 2009. At December 31, 2008, Mississippi Power had spent $42.3 million of the $61 million, of which $3.7 million related to land purchases capitalized. Of the remaining amount, $0.8 million was expensed and $37.8 million was deferred in other regulatory assets.

The final outcome of this matter cannot now be determined.

Nuclear

In August 2006, 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), filed an application with the Nuclear Regulatory Commission (NRC) for an early site permit relating to two additional nuclear units on the site of Plant Vogtle. See Note 4 to the financial statements for additional information on these co-owners. On March 31, 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units.

On August 1, 2008, Georgia Power submitted an application for the Georgia PSC to certify the project. Hearings began November 3, 2008 and a final certification decision is expected in March 2009.

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Southern Company and Subsidiary Companies 2008 Annual Report

The Vogtle 3 and 4 Agreement is subject to certification by the Georgia PSC. In addition, the Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

Southern Company is also exploring other possibilities relating to additional nuclear power projects, both on its own or in partnership with other utilities. 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 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 July 2007, the government filed a motion for reconsideration, which was denied in November 2007. On January 2, 2008, the government filed an appeal, and on February 29, 2008, filed a motion to stay the appeal. On April 1, 2008, the court 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. Based on the rulings in those cases, the appeal is expected to proceed in first quarter 2009.

On April 3, 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. On October 31, 2008, the court 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, 2008 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. Expanded wet storage capacity and 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.

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Southern Company and Subsidiary Companies 2008 Annual Report

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, 2008, 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)		45.7	%	$	3,303	$	1,918
Plant Hatch (nuclear)		50.1			953		521
Plant Miller (coal) Units 1 and 2		91.8			986		425
Plant Scherer (coal) Units 1 and 2		8.4			117		68
Plant Wansley (coal)		53.5			552		189
Rocky Mountain (pumped storage)		25.4			175		102
Intercession City (combustion turbine)		33.3			12		3
Plant Stanton (combined cycle) Unit A		65.0			151		14

At December 31, 2008, the portion of total construction work in progress related to Plants Miller, Scherer, and Wansley was $174 million, $247 million, and $114 million, respectively, primarily for environmental projects.

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

5. INCOME TAXES

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

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Southern Company and Subsidiary Companies 2008 Annual Report

Current and Deferred Income Taxes

Details of income tax provisions are as follows:


	2008		2007			2006
	(in millions)
Federal —
Current	$	628	$	715		$	465
Deferred		177		11			207

		805		726			672

State —
Current		72		114			110
Deferred		38		(5	)		(2	)

		110		109			108

Total	$	915	$	835		$	780

Net cash payments for income taxes in 2008, 2007, and 2006 were $537 million, $732 million, and $649 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:


	2008			2007
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	5,356		$	4,878
Property basis differences		968			950
Leveraged lease basis differences		306			479
Employee benefit obligations		364			856
Under recovered fuel clause		516			443
Premium on reacquired debt		107			114
Regulatory assets associated with employee benefit obligations		869			303
Regulatory assets associated with asset retirement obligations		480			483
Other		132			140

Total		9,098			8,646

Deferred tax assets —
Federal effect of state deferred taxes		354			305
State effect of federal deferred taxes		105			97
Employee benefit obligations		1,325			656
Other property basis differences		144			147
Deferred costs		99			131
Unbilled revenue		100			90
Other comprehensive losses		82			48
Regulatory liabilities associated with employee benefit obligations		—			514
Asset retirement obligations		480			483
Other		279			259

Total		2,968			2,730

Total deferred tax liabilities, net		6,130			5,916
Portion included in prepaid expenses (accrued income taxes), net		(90	)		(106	)
Deferred state tax assets		103			88
Valuation allowance		(63	)		(59	)

Accumulated deferred income taxes	$	6,080		$	5,839

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Southern Company and Subsidiary Companies 2008 Annual Report

At December 31, 2008, 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 $57 million, if utilized. However, Southern Company has established a valuation allowance for the potential $57 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs will expire between 2009 and 2021. During 2008, Southern Company utilized $5.8 million in available NOLs, which resulted in a $0.3 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, 2008, the tax-related regulatory assets and liabilities were $972 million and $260 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized investment tax credits.

In accordance with regulatory requirements, deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $23 million in 2008, $23 million in 2007, and $23 million in 2006. At December 31, 2008, all investment tax credits available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

The provision for income taxes differs from the amount of income taxes determined by applying the applicable U.S. federal statutory rate to earnings before income taxes and preferred and preference dividends of subsidiaries, as a result of the following:


	2008			2007			2006

Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		2.6			2.7			2.9
Synthetic fuel tax credits		—			(1.4	)		(2.7	)
Employee stock plans dividend deduction		(1.3	)		(1.3	)		(1.4	)
Non-deductible book depreciation		0.8			0.9			1.0
Difference in prior years’ deferred and current tax rate		(0.2	)		(0.2	)		(0.3	)
AFUDC-Equity		(1.9	)		(1.4	)		(0.7	)
Production activities deduction		(0.4	)		(0.8	)		(0.2	)
Donations		—			(0.8	)		—
Other		(1.0	)		(0.8	)		(0.9	)

Effective income tax rate		33.6	%		31.9	%		32.7	%

Southern Company’s effective tax rate increased due to the unavailability of the synthetic fuel tax credits in 2008. The credits were no longer allowed under Internal Revenue Code Section 45K for production after December 31, 2007.

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 years 2007 through 2009, and a 9% rate thereafter. This increase from 3% in 2006 to 6% in 2007 was one of several

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factors that increased Southern Company’s 2007 deduction by $32 million over the 2006 deduction. The resulting additional tax benefit was $11 million. The IRS has not clearly defined a methodology for calculating this deduction. However, Southern Company has agreed with the IRS on a calculation methodology and signed a closing agreement on December 11, 2008. Therefore, Southern Company reversed the unrecognized tax benefit 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. 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.

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 donation caused a lower effective income tax rate for the year ended December 31, 2007, when compared to December 31, 2008.

Unrecognized Tax Benefits

FIN 48 requires companies to determine whether it is “more likely than not” that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. It also provides guidance on the recognition, measurement, and classification of income tax uncertainties, along with any related interest and penalties. For 2008, the total amount of unrecognized tax benefits decreased by $118 million, resulting in a balance of $146 million as of December 31, 2008.

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


	2008			2007
	(in millions)

Unrecognized tax benefits at beginning of year	$	264		$	211
Tax positions from current periods		49			46
Tax positions from prior periods		130			7
Reductions due to settlements		(297	)		—

Balance at end of year	$	146		$	264

The tax positions from current periods increase for 2008 relate primarily to the Georgia state tax credits litigation and other miscellaneous uncertain tax positions. The tax positions from prior periods increase for 2008 relate primarily to the SILO transactions that was remeasured during the second quarter 2008 and effectively settled in December 2008. The reduction due to settlements relates to the agreement with the IRS on the SILO transactions and the agreement with the IRS regarding the production activities deduction methodology. The results of the effective settlement of the SILO transactions were related to timing differences and therefore had no impact on income. See Note 3 under “Income Tax Matters” for additional information.

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


	2008		2007		Change
	(in millions)

Tax positions impacting the effective tax rate	$	143	$	96	$	47
Tax positions not impacting the effective tax rate		3		168		(165	)

Balance of unrecognized tax benefits	$	146	$	264	$	(118	)

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Southern Company and Subsidiary Companies 2008 Annual Report

The tax positions impacting the effective tax rate increase of $47 million primarily relate to Georgia state tax credit litigation at Georgia Power. The $165 million decrease in tax positions not impacting the effective tax rate relates to the effective settlement of the SILO transactions. See Note 3 under “Income Tax Matters.”

Accrued interest for unrecognized tax benefits:


	2008			2007
	(in millions)

Interest accrued at beginning of year	$	31		$	27
Interest reclassified due to settlements		(49	)		—
Interest accrued during the year		33			4

Balance at end of year	$	15		$	31

Southern Company classifies interest on tax uncertainties as interest expense. The net amount of interest accrued during the period was primarily associated with the SILO transactions and the Georgia state tax credit litigation. Interest reclassified due to settlements relates to the SILO transactions effective settlement agreement and the production activities deduction methodology. These amounts have been reclassified from interest on tax uncertainties to current interest payable.

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 federal or 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 2002.

6. FINANCING

Long-Term Debt Payable to Affiliated Trusts

Southern Company and 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 Southern Company or 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.” Southern Company and 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, 2008, 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.

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Southern Company and Subsidiary Companies 2008 Annual Report

Securities Due Within One Year

A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows:


	2008		2007
	(in millions)

Capitalized leases	$	20	$	15
Senior notes		565		1,005
Other long-term debt		32		33
Preferred stock		—		125

Total	$	617	$	1,178

Debt and preferred stock redemptions, and/or serial maturities through 2013 applicable to total long-term debt are as follows: $617 million in 2009; $1.1 billion in 2010; $825 million in 2011; $1.8 billion in 2012; and $950 million in 2013.

Bank Term Loans

Certain of the traditional operating companies entered into bank term loan agreements in 2008. Georgia Power borrowed $300 million under a three-year term loan agreement and $100 million under a short-term loan agreement. Gulf Power borrowed $110 million under a three-year loan agreement and $50 million under a short-term loan agreement. Mississippi Power also borrowed $80 million under a three-year term loan agreement. The proceeds of these loans were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes. Another Southern Company subsidiary had outstanding long-term bank loans of $184 million at December 31, 2008.

Senior Notes

Southern Company and its subsidiaries issued a total of $2.5 billion of senior notes in 2008. Southern Company issued $600 million, and the traditional operating companies’ combined issuances totaled $1.9 billion. The proceeds of these issuances were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes.

At December 31, 2008 and 2007, Southern Company and its subsidiaries had a total of $12.9 billion and $11.4 billion, respectively, of senior notes outstanding. At December 31, 2008 and 2007, Southern Company had a total of $1.1 billion and $900 million, respectively, of senior notes outstanding.

Subsequent to December 31, 2008, Georgia Power issued $500 million long-term senior notes. The proceeds were used to repay long-term and short-term indebtedness and for other general corporate purposes.

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.

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Southern Company and Subsidiary Companies 2008 Annual Report

Bank Credit Arrangements

At December 31, 2008, unused credit arrangements with banks totaled $4.2 billion, of which $970 million expires during 2009, $25 million expires in 2011, and $3.2 billion expires in 2012. The following table outlines the credit arrangements by company:


					Expires
Company	Total		Unused		2009		2011		2012
	(in millions)

Alabama Power	$	1,256	$	1,256	$	466	$	25	$	765
Georgia Power		1,345		1,333		225		—		1,120
Gulf Power		120		120		120		—		—
Mississippi Power		99		99		99		—		—
Southern Company		950		950		—		—		950
Southern Power		400		400		—		—		400
Other		60		60		60		—		—

Total	$	4,230	$	4,218	$	970	$	25	$	3,235

Approximately $84 million of the credit facilities expiring in 2009 allow the execution of term loans for an additional two-year period and $544 million allow execution of one-year term loans. Most of these agreements include stated borrowing rates.

All of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average one-eighth 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, 2008, 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 $4.2 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, 2008 was approximately $1.3 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, 2008 and December 31, 2007 were $794.3 million and $1.2 billion, respectively. The amounts of short-term bank loans included in notes payable in the balance sheets at December 31, 2008 and December 31, 2007 were $150 million and $113 million, respectively.

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Southern Company and Subsidiary Companies 2008 Annual Report

During 2008, the peak amount outstanding for short-term debt was $1.7 billion, and the average amount outstanding was $1.1 billion. The average annual interest rate on short-term debt was 2.7% for 2008 and 5.3% for 2007.

Financial Instruments

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. Southern Power also 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. Each of the traditional operating companies manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. In addition to hedges on fuel and purchased power, the traditional operating companies and Southern Power may also enter into hedges of forward electricity sales.

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:


	2008			2007
	(in millions)

Regulatory hedges	$	(288	)	$	—
Cash flow hedges		( 1	)		1
Non-accounting hedges		4			3

Total fair value	$	(285	)	$	4

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 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 transactions. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. The pre-tax gains/(losses) reclassified from other comprehensive income to revenue and fuel expense were not material for any period presented and are not expected to be material for 2009. Additionally, no material ineffectiveness was recorded in earnings for any period presented. Southern Company has energy-related hedges in place up to and including 2012.

During 2006 and 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 increases. These derivatives settled on January 1, 2008 and thus there was no income statement impact for the period ended December 31, 2008. At December 31, 2007, the fair value of all derivative transactions related to synthetic fuel production was a $43 million net asset. For 2007 and 2006, the fair value gain/(loss) recognized in other income (expense) to mark the transactions to market was $27 million and $(32) million, respectively.

Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to changes in interest rates. Derivatives related to fixed-rate securities are accounted for as fair value hedges. Derivatives related to 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. As such, no material ineffectiveness has been recorded in earnings for any period presented.

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Southern Company and Subsidiary Companies 2008 Annual Report

At December 31, 2008, Southern Company had $1.4 billion notional amount of interest rate derivatives outstanding with net fair value losses of $40 million as follows:

Cash Flow Hedges


				Weighted				Fair Value
	Notional		Variable Rate	Average			Hedge Maturity	Gain (Loss)
	Amount		Received	Fixed Rate Paid			Date	December 31, 2008
	(in millions)							(in millions)

*Cash Flow Hedges on Existing Debt*
Alabama Power*	$	576	SIFMA Index		2.69	%	February 2010	$	(11	)
Georgia Power*		301	SIFMA Index		2.22	%	December 2009		(3	)
Georgia Power		150	3-month LIBOR		2.63	%	February 2009		(-	)
Georgia Power		300	1-month LIBOR		2.43	%	April 2010		(5	)

*Cash Flow Hedges on Forecasted Debt*
Georgia Power		100	3-month LIBOR		4.98	%	February 2019		(21	)


*		Hedged using the Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA) (formerly the Bond Market Association/PSA Municipal Swap Index)

For fair value hedges, the changes in the fair value of the hedging derivatives are recorded in earnings and are offset by the changes in the fair value of the hedged item. The Company did not have any fair value hedges as of December 31, 2008.

The fair value gains/(losses) for cash flow hedges are recorded in other comprehensive income and are reclassified into earnings at the same time the hedged items affect earnings. In 2008, 2007, and 2006, the Company incurred net gains/(losses) of $(26) million, $9 million, and $1 million, respectively, upon termination of certain interest derivatives at the same time it issued debt. The effective portion of these gains/(losses) has been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative. The Company also settled an interest derivative early because of counterparty credit issues at a loss of $(2) million. This loss is deferred in other comprehensive income and will be amortized into earnings once the forecasted debt is issued in 2009. For 2008, 2007, and 2006, approximately $(19) million, $(15) million, and $(1) million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2009, pre-tax losses of approximately $(34) million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2019 and has deferred realized gains/(losses) that are being amortized through 2037.

Subsequent to December 31, 2008, Georgia Power settled $100 million of hedges related to the forecasted debt issuance in February 2009 at a loss of approximately $16 million. This loss will be amortized into earnings over 10 years.

All derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. See Note 10 for additional information.

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Southern Company and Subsidiary Companies 2008 Annual Report

7. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently estimated to total $5.7 billion in 2009, $5.1 billion in 2010, and $5.8 billion in 2011. These amounts include $187 million, $151 million, and $150 million in 2009, 2010, and 2011, 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; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. At December 31, 2008, 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.

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.

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 $2.3 billion over the remaining life of the agreements, which are currently estimated to range up to 28 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 $10 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 begun construction of flue gas desulfurization projects and have entered into various long-term commitments for the procurement of limestone to be used in such 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 7.5 million tons, equating to approximately $299 million, through 2019. Estimated expenditures (based on minimum contracted obligated dollars) over the next five years are, $13 million in 2009, $35 million in 2010, $35 million in 2011, $36 million in 2012, and $36 million in 2013.

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Southern Company and Subsidiary Companies 2008 Annual Report

Fuel and Purchased Power Commitments

To supply a portion of the fuel requirements of the generating plants, Southern Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. Coal commitments include forward contract purchases for sulfur dioxide and nitrogen oxide emission allowances. Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery; amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2008. 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, 2008 were as follows:


	Commitments
	Natural Gas		Coal		Nuclear Fuel		Purchased Power
	(in millions)

2009	$	1,507	$	4,608	$	187	$	217
2010		969		3,333		151		239
2011		640		2,666		150		216
2012		611		1,370		152		222
2013		631		1,232		123		191
2014 and thereafter		3,798		3,421		43		1,938

Total	$	8,156	$	16,630	$	806	$	3,023

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 $147 million in 2008, $144 million in 2007, and $137 million in 2006.

Operating Leases

In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The initial lease term ends in 2011, and the lease includes a purchase and 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. Eighteen months prior to the end of the initial lease, Mississippi Power may elect to renew for 10 years. If the lease is renewed, the agreement calls for Mississippi Power to amortize an additional 17% of the initial completion cost over the renewal period. Upon termination of the lease, at Mississippi Power’s option, it may either exercise its purchase option or the facility can be sold to a third party.

The lease provides for a residual value guarantee, approximately 73% 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 $5 million, $7 million, and $9 million for the fair market value of this residual value guarantee is included in the balance sheets as of December 31, 2008, 2007, and 2006, respectively.

Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $184 million, $187 million, and $181 million for 2008, 2007, and 2006, 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.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

At December 31, 2008, estimated minimum lease payments for noncancelable operating leases were as follows:


	Minimum Lease Payments
	Plant Daniel		Barges & Rail Cars		Other		Total
	(in millions)
2009	$	29	$	66	$	48	$	143
2010		28		46		42		116
2011		28		34		34		96
2012		—		21		25		46
2013		—		18		17		35
2014 and thereafter		—		40		106		146

Total	$	85	$	225	$	272	$	582

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.

Guarantees

Prior to the Mirant spin-off, Southern Company made separate guarantees to certain counterparties regarding performance of contractual commitments by Mirant’s trading and marketing subsidiaries. The total notional amount of the guarantees is not material.

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 2008, Southern Company raised $474 million from the issuance of 14.1 million new common shares under the Company’s various stock programs. In 2007, Southern Company raised $379 million from the issuance of 11.6 million new common shares and $159 million from the re-issuance of 5.3 million shares of treasury stock under the Company’s various stock programs.

Shares Reserved

At December 31, 2008, a total of 72 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, 2008, there were 7,009 current and former employees participating in the stock option plan, and there were 33.2 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.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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 2008, 2007, and 2006 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	2008			2007			2006

Expected volatility		13.1	%		14.8	%		16.9	%
Expected term (in years)		5.0			5.0			5.0
Interest rate		2.8	%		4.6	%		4.6	%
Dividend yield		4.5	%		4.3	%		4.4	%
Weighted average grant-date fair value	$	2.37		$	4.12		$	4.15

Southern Company’s activity in the stock option plan for 2008 is summarized below:


	Shares Subject			Weighted Average
	To Option			Exercise Price

Outstanding at December 31, 2007		34,074,622		$	30.77
Granted		7,084,902			35.78
Exercised		(4,112,651	)		27.42
Cancelled		(105,600	)		34.70

Outstanding at December 31, 2008		36,941,273		$	32.09

Exercisable at December 31, 2008		24,194,943		$	30.20

The number of stock options vested, and expected to vest in the future, as of December 31, 2008 was not significantly different from the number of stock options outstanding at December 31, 2008 as stated above. As of December 31, 2008, the weighted average remaining contractual term for the options outstanding and options exercisable was 6.3 years and 5.1 years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $181 million and $165 million, respectively.

As of December 31, 2008, there was $7 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, 2008, 2007, and 2006, total compensation cost for stock option awards recognized in income was $20 million, $28 million, and $28 million, respectively, with the related tax benefit also recognized in income of $8 million, $11 million, and $11 million, respectively.

The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 was $45 million, $81 million, and $36 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $17 million, $31 million, and $14 million, respectively, for the years ended December 31, 2008, 2007, and 2006.

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

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, 2008, 2007, and 2006 was $113 million, $195 million, and $77 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
	2008		2007		2006
	(in thousands)

As reported shares		771,039		756,350		743,146
Effect of options		3,809		4,666		4,739

Diluted shares		774,848		761,016		747,885

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2008, consolidated retained earnings included $5.3 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, 2008, 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 $12.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $300 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of 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.

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

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Southern Company and Subsidiary Companies 2008 Annual Report

period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase the maximum limit allowed by NEIL, subject to ownership limitations. Each facility has elected a 12-week waiting period.

Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $39 million and $51 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

On January 1, 2008, Southern Company adopted FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value, and requires additional disclosures about fair value measurements. The criterion that is set forth in SFAS No. 157 is applicable to fair value measurement where it is permitted or required under other accounting pronouncements.

SFAS No. 157 defines fair value as the exit price, which is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement. As a means to illustrate the inputs used, SFAS No. 157 establishes 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 2008 Annual Report

The adoption of SFAS No. 157 has not resulted in any significant changes to the methodologies used for fair value measurement. Primarily all the changes in the fair value of assets and liabilities are recorded in other comprehensive income or regulatory assets and liabilities, and thus the impact on earnings is limited to derivatives that do not qualify for hedge accounting.

The fair value measurements performed on a recurring basis and the level of the fair value hierarchy in which they fall at December 31, 2008 are as follows:


At December 31, 2008:	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Energy-related derivatives	$	—	$	22	$	—	$	22
Nuclear decommissioning trusts^(a)		498		364		—		862
Cash equivalents and restricted cash		469		—		—		469
Other		2		46		35		83

Total fair value	$	969	$	432	$	35	$	1,436


Liabilities:
Energy-related derivatives	$	—	$	307	$	—	$	307
Interest rate derivatives		—		40		—		40

Total fair value	$	—	$	347	$	—	$	347

(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 6 under “Financial Instruments” 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.

Changes in the fair value measurement of the Level 3 items for the year ended December 31, 2008 are as follows:


	Level 3
	Other
	(in millions)
Beginning balance at December 31, 2007	$	50
Total gains (losses) — realized/unrealized:
Included in other comprehensive income		(12	)
Purchases, issuances and settlements		1
Transfers in and/or out of Level 3		(4	)

Ending balance at December 31, 2008	$	35

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

11. 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 $638 million, $547 million, and $492 million in 2008, 2007, and 2006, 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, energy-related services, and leveraged lease projects. Also included are investments in synthetic fuels for 2007 and 2006. In addition, see Note 1 under “Related Party Transactions” for information regarding revenues from services for synthetic fuel production that are included in the cost of fuel purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

Business Segments


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
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


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
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


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
2006
Operating revenues	$	13,920	$	777	$	(609	)	$	14,088	$	413		$	(145	)	$	14,356
Depreciation and amortization		1,098		66		—			1,164		37			(1	)		1,200
Interest income		33		2		—			35		7			(1	)		41
Interest expense		637		80		—			717		149			—			866
Income taxes		867		82		—			949		(169	)		—			780
Segment net income (loss)		1,462		124		—			1,586		(11	)		(2	)		1,573
Total assets		38,825		2,691		(110	)		41,406		1,933			(481	)		42,858
Gross property additions		2,561		501		(16	)		3,046		26			—			3,072

Products and Services


Electric Utilities’ Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2008	$	14,055	$	2,400	$	545	$	17,000
2007		12,639		1,988		513		15,140
2006		11,801		1,822		465		14,088

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NOTES (continued)
Southern Company and Subsidiary Companies 2008 Annual Report

12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2008 and 2007 are as follows:



							Per Common Share
											Trading
	Operating		Operating		Consolidated		Basic				Price Range
Quarter Ended	Revenues		Income		Net Income		Earnings		Dividends		High		Low
			(in millions)
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

March 2007	$	3,409	$	691	$	339	$	0.45	$	0.3875	$	37.25	$	34.85
June 2007		3,772		844		429		0.57		0.4025		38.90		33.50
September 2007		4,832		1,382		762		1.00		0.4025		37.70		33.16
December 2007		3,340		409		204		0.27		0.4025		39.35		35.15

Southern Company’s business is influenced by seasonal weather conditions.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2004 through 2008
Southern Company and Subsidiary Companies 2008 Annual Report



	2008		2007		2006		2005		2004


Operating Revenues (in millions)	$	17,127	$	15,353	$	14,356	$	13,554	$	11,729
Total Assets (in millions)	$	48,347	$	45,789	$	42,858	$	39,877	$	36,955
Gross Property Additions (in millions)	$	4,122	$	3,658	$	3,072	$	2,476	$	2,099
Return on Average Common Equity (percent)		13.57		14.60		14.26		15.17		15.38
Cash Dividends Paid Per Share of Common Stock	$	1.6625	$	1.595	$	1.535	$	1.475	$	1.415
Consolidated Net Income (in millions):	$	1,742	$	1,734	$	1,573	$	1,591	$	1,532
Earnings Per Share —
Basic	$	2.26	$	2.29	$	2.12	$	2.14	$	2.07
Diluted		2.25		2.28		2.10		2.13		2.06

Capitalization (in millions):
Common stock equity	$	13,276	$	12,385	$	11,371	$	10,689	$	10,278
Preferred and preference stock		1,082		1,080		744		596		561
Long-term debt		16,816		14,143		12,503		12,846		12,449

Total (excluding amounts due within one year)	$	31,174	$	27,608	$	24,618	$	24,131	$	23,288

Capitalization Ratios (percent):
Common stock equity		42.6		44.9		46.2		44.3		44.1
Preferred and preference stock		3.5		3.9		3.0		2.5		2.4
Long-term debt		53.9		51.2		50.8		53.2		53.5

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	$	17.08	$	16.23	$	15.24	$	14.42	$	13.86
Market price per share:
High	$	40.60	$	39.35	$	37.40	$	36.47	$	33.96
Low		29.82		33.16		30.48		31.14		27.44
Close (year-end)		37.00		38.75		36.86		34.53		33.52
Market-to-book ratio (year-end) (percent)		216.6		238.8		241.9		239.5		241.8
Price-earnings ratio (year-end) (times)		16.4		16.9		17.4		16.1		16.2
Dividends paid (in millions)	$	1,279	$	1,204	$	1,140	$	1,098	$	1,044
Dividend yield (year-end) (percent)		4.5		4.1		4.2		4.3		4.2
Dividend payout ratio (percent)		73.5		69.5		72.4		69.0		68.3
Shares outstanding (in thousands):
Average		771,039		756,350		743,146		743,927		738,879
Year-end		777,192		763,104		746,270		741,448		741,495
Stockholders of record (year-end)		97,324		102,903		110,259		118,285		125,975

Traditional Operating Company Customers (year-end) (in thousands):
Residential		3,785		3,756		3,706		3,642		3,600
Commercial		594		600		596		586		578
Industrial		15		15		15		15		14
Other		8		6		5		5		5

Total		4,402		4,377		4,322		4,248		4,197

Employees (year-end)		27,276		26,742		26,091		25,554		25,642

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2004 through 2008
Southern Company and Subsidiary Companies 2008 Annual Report



	2008		2007		2006		2005		2004


Operating Revenues (in millions):
Residential	$	5,476	$	5,045	$	4,716	$	4,376	$	3,848
Commercial		5,018		4,467		4,117		3,904		3,346
Industrial		3,445		3,020		2,866		2,785		2,446
Other		116		107		102		100		92

Total retail		14,055		12,639		11,801		11,165		9,732
Wholesale		2,400		1,988		1,822		1,667		1,341

Total revenues from sales of electricity		16,455		14,627		13,623		12,832		11,073
Other revenues		672		726		733		722		656

Total	$	17,127	$	15,353	$	14,356	$	13,554	$	11,729

Kilowatt-Hour Sales (in millions):
Residential		52,262		53,326		52,383		51,082		49,702
Commercial		54,427		54,665		52,987		51,857		50,037
Industrial		52,636		54,662		55,044		55,141		56,399
Other		934		962		920		996		1,005

Total retail		160,259		163,615		161,334		159,076		157,143
Sales for resale		39,368		40,745		38,460		37,072		34,568

Total		199,627		204,360		199,794		196,148		191,711

Average Revenue Per Kilowatt-Hour (cents):
Residential		10.48		9.46		9.00		8.57		7.74
Commercial		9.22		8.17		7.77		7.53		6.69
Industrial		6.54		5.52		5.21		5.05		4.34
Total retail		8.77		7.72		7.31		7.02		6.19
Wholesale		6.10		4.88		4.74		4.50		3.88
Total sales		8.24		7.16		6.82		6.54		5.78
Average Annual Kilowatt-Hour
Use Per Residential Customer		13,844		14,263		14,235		14,084		13,879
Average Annual Revenue
Per Residential Customer	$	1,451	$	1,349	$	1,282	$	1,207	$	1,074
Plant Nameplate Capacity
Ratings (year-end) (megawatts)		42,607		41,948		41,785		40,509		38,622
Maximum Peak-Hour Demand (megawatts):
Winter		32,604		31,189		30,958		30,384		28,467
Summer		37,166		38,777		35,890		35,050		34,414
System Reserve Margin (at peak) (percent)		15.3		11.2		17.1		14.4		20.2
Annual Load Factor (percent)		58.7		57.6		60.8		60.2		61.4
Plant Availability (percent):
Fossil-steam		90.5		90.5		89.3		89.0		88.5
Nuclear		91.3		90.8		91.5		90.5		92.8

Source of Energy Supply (percent):
Coal		64.0		67.1		67.2		67.4		65.0
Nuclear		14.0		13.4		14.0		14.0		14.5
Hydro		1.4		0.9		1.9		3.1		2.9
Oil and gas		15.4		15.0		12.9		10.9		10.9
Purchased power		5.2		3.6		4.0		4.6		6.7

Total		100.0		100.0		100.0		100.0		100.0

C-99

BOARD OF DIRECTORS

1. David M. Ratcliffe

Chairman, President, and CEO

Southern Company

Atlanta, Georgia

Age 60; elected 2003

Other corporate directorships:

CSX Corporation and Southern system companies —

Alabama Power Company, Georgia Power Company,

Southern Power Company

2. Juanita Powell Baranco

Executive Vice President and

Chief Operating Officer

Baranco Automotive Group

(automobile sales)

Morrow, Georgia

Age 60: elected 2006

Board committees: Governance (chair) and

Nuclear/Operations

Other corporate directorships:

Cox Radio, Inc.

3. Francis S. Blake

Chairman and CEO

The Home Depot Inc.

(home improvement)

Atlanta, Georgia

Age 59: elected 2004

Board committee: Audit

Other corporate directorships:

The Home Depot Inc.

4. Jon A. Boscia

President

Sun Life Financial Inc.

(financial services)

Gladwyne, Pennsylvania

Age 56; elected 2007

Board committees: Compensation

and Management Succession, Finance

Other corporate directorships: Armstrong World
Industries

5. Thomas F. Chapman, Presiding Director

Retired Chairman and CEO

Equifax Inc. (information services,

data analytics, transaction processing, and consumer

financial products)

Atlanta, Georgia

Age 65; elected 1999

Board committee: Governance

Other corporate directorships: None

6. H. William Habermeyer, Jr.

Retired President and CEO

Progress Energy Florida, Inc.(energy)

St. Petersburg, Florida

Age 66; elected 2007

Board committees: Nuclear/Operations

(chair) and Compensation and Management

Succession

Other corporate directorships:

Raymond James Financial Inc.,

USEC Inc.

7. Veronica M. Hagen

CEO

Polymer Group, Inc. (engineered materials)

Age 63; elected 2008

Board committees: Governance, Nuclear/Operations

Other corporate directorships: Polymer Group, Inc.,
Newmont Mining Corporation

8. Warren A. Hood, Jr.

Chairman and CEO

Hood Companies Incorporated (packaging and

construction products)

Hattiesburg, Mississippi

Age 57; elected 2007

Board committee: Audit

Other corporate directorships: Hood Companies
Incorporated, BancorpSouth Bank

9. Donald M. James

Chairman and CEO

Vulcan Materials Company

(construction materials)

Birmingham, Alabama

Age 60; elected 1999

Board committees: Finance (chair),

Compensation and Management Succession

Other corporate directorships:

Vulcan Materials Company, Wells Fargo & Company

10. J. Neal Purcell

Retired Vice Chairman-Audit Operations

KPMG (audit and accounting)

Duluth, Georgia

Age 67; elected 2003

Board committees: Compensation and

Management Succession (chair), Finance

Other corporate directorships:

Kaiser Permanente Health Care and Hospitals,
Synovus Financial Corp.

C-100

11. William G. Smith, Jr.

Chairman, President, and CEO

Capital City Bank Group Incorporated

(banking)

Tallahassee, Florida

Age 55; elected 2006

Board committees: Audit (chair)

Other corporate directorships:

Capital City Bank Group, Inc., Capital City Bank

12. Gerald J. St. Pé

Former President

Ingalls Shipbuilding

Retired Executive Vice President

Litton Industries (shipbuilding)

Pascagoula, Mississippi

Age 69; elected 1995

Board committees: Governance, Nuclear/Operations

Other corporate directorships: Merchants and Marine Bank, Signal International

C-101

MANAGEMENT COUNCIL

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

Ratcliffe, 60, 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, 52, joined the Company as a residential sales representative with Gulf Power in 1979. He has held his current position since February 1, 2008. Previously, he served as president of Southern Company Generation, with overall responsibility for fossil and hydro generation and operations, Southern Power, wholesale energy, engineering and construction services, fuel procurement, energy trading, and research and environmental affairs. Bowers has also served as president and CEO of Southern Power and president and CEO of Southern Company’s former United Kingdom subsidiary.

3. Thomas A. Fanning
Executive Vice President and
Chief Operating Officer

Fanning, 52, joined the Company as a financial analyst in 1980. In his current position since February 1, 2008, Fanning is responsible for Southern Company Generation — which includes non-nuclear generating facilities and environmental affairs — Southern Power, and Southern Company transmission. He remains responsible for corporate strategy. Previously, Fanning served as chief financial officer. He also served as president and CEO of Gulf Power and chief financial officer at Georgia Power and Mississippi Power. Fanning has held several officer positions in the areas of finance, strategy, international business development, and information technology.

4. Michael D. Garrett
Executive Vice President
President and CEO, Georgia Power

Garrett, 59, joined the Company as a cooperative-education student with Georgia Power in 1968. He began his current job in 2004. Previously, Garrett was president and CEO of Mississippi Power. He has held executive positions at Alabama Power in the areas of customer operations, regulatory affairs, finance, and external affairs, as well as serving as Birmingham Division vice president.

5. G. Edison Holland Jr.
Executive Vice President, General Counsel,
and Corporate Secretary

Holland, 56, 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 has also served as vice president of power generation and transmission at Gulf Power.

6. C. Alan Martin
Executive Vice President
President and CEO, Southern Company Services

Martin, 60, joined the Company as a right-of-way agent at Alabama Power in 1972. He has held his current position since February 1, 2008. Martin has 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.

C-102

7. Charles D. McCrary
Executive Vice President
President and CEO, Alabama Power

McCrary, 57, joined the Company as an assistant project planning engineer with Alabama Power in 1973. He began his current job 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, 59, joined the Company as corporate counsel for Southern Nuclear in 1994. He began his current job in 2008. Previously, Miller served as senior vice president, compliance officer, and general counsel at Georgia Power. He has also held positions of senior vice president of external affairs and senior vice president of the Birmingham Division at Alabama Power.

9. Susan N. Story
President and CEO, Gulf Power

Story, 49, joined the Company as a nuclear power plant engineer in 1982. She has held her current position since 2003. Previously, Story was executive vice president of engineering and construction services for Southern Company Generation and Energy Marketing. She has held executive and management positions in the areas of supply chain management, real estate, corporate services, and human resources.

10. Anthony J. Topazi
President and CEO, Mississippi Power

Topazi, 58, joined the Company as a cooperative-education student with Alabama Power in 1969. He began his current job in 2004. Topazi previously was executive vice president for Southern Company Generation and Energy Marketing and also served as senior vice president of Southern Power. He has held various positions at Alabama Power, including Western Division vice president and Birmingham Division vice president.

11. Christopher C. Womack
Executive Vice President and
President, External Affairs

Womack, 51, joined the Company as a governmental affairs representative for Alabama Power in 1988. He has held his current position since January 2009. Previously, Womack was executive vice president of external affairs for Georgia Power. He has held executive and management positions including the Company’s senior vice president of human resources and chief people officer, and senior vice president and senior production officer of Southern Company Generation.

C-103

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@southernco.com

Stockholder Services Internet Site

Located within Southern Company’s Investor Relations Web site 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 (SIP) 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 2008 is taxable. The board of directors sets the record and payment dates for quarterly dividends. A dividend of 42 cents per share was paid in March 2009. For the remainder of 2009, projected record dates are May 4, August 3, and November 2. Projected payment dates for dividends declared during the remainder of 2009 are June 6, September 5, and December 5.

Auditors

Deloitte & Touche LLP

191 Peachtree St. NE

Suite 1500

Atlanta, GA 30303

During 2008, there were no changes in or disagreements with the auditors on accounting and financial disclosure.

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Investor Information Line

For recorded information about earnings and dividends, stock quotes, and current news releases, call toll-free 866-762-6411.

Institutional Investor Inquiries

Southern Company maintains an investor relations office in Atlanta, 404-506-5195 to meet the information needs of institutional investors and securities analysts.

Electronic Delivery Of Proxy Materials

Any stockholder may enroll for electronic delivery of proxy materials at www.icsdelivery.com/so.

Certifications

Southern Company has filed the required certifications of its chief executive officer and chief financial officer under Section 302 of the Sarbanes-Oxley Act of 2002, regarding the quality of its public disclosures as exhibits 31(a)1 and 31(a)2, respectively — to Southern Company’s Annual Report on Form 10-K for the year ended December 31, 2008. The certification of Southern Company’s chief executive officer regarding compliance with the New York Stock Exchange (NYSE) corporate governance listing standards, required by NYSE Rule 303A.12, will be filed with the NYSE following the 2009 Annual Meeting of Stockholders. Last year, Southern Company filed this certification with the NYSE on June 9, 2008.

Environmental Information

Southern Company publishes a variety of information on its activities to meet the company’s environmental commitments. It is available online at www.southerncompany.com/planetpower/ and in print. To request printed materials, write to:

Chris Hobson
Senior Vice President, Research and Environmental Affairs
600 North 18th St.
Bin 14N-8195
Birmingham, AL 35203-2206

Common Stock

Southern Company common stock is listed on the NYSE under the ticker symbol SO. On December 31, 2008, Southern Company had 97,324 stockholders of record.

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Recycled Paper

(SOUTHERN COMPANY LOGO)

THE SOUTHERN COMPANY

30 IVAN ALLEN, JR. BLVD. NW

11TH FLOOR-BIN SC1100

ATLANTA, GA 30308

Please consider furnishing your voting instructions electronically by Internet or phone. Processing paper forms is more than twice as expensive as electronic instructions.

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 web site and follow the instructions to obtain your records and to create an electronic voting instruction form.

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, proxy cards and annual reports 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.

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.

THANK YOU

VIEW THE PROXY STATEMENT ON THE INTERNET

www.southerncompany.com

TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:x	M11946	KEEP THIS PORTION FOR YOUR RECORDS
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THIS FORM OF PROXY OR TRUSTEE VOTING INSTRUCTION FORM IS VALID ONLY WHEN SIGNED AND DATED.		DETACH AND RETURN THIS PORTION ONLY

THE SOUTHERN COMPANY

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.

The Board of Directors recommends a vote FOR Items

1, 2, 3 and 4 and AGAINST Items 5 and 6.

1. ELECTION OF DIRECTORS					0	0	0	________________________________________________
	Nominees:
	01)	J. P. Baranco	07)	W. A. Hood, Jr.
	02)	F. S. Blake	08)	D. M. James
	03)	J. A. Boscia	09)	J. N. Purcell
	04)	T. F. Chapman	10)	D. M. Ratcliffe
	05)	H. W. Habermeyer, Jr.	11)	W. G. Smith, Jr.
	06)	V. M. Hagen	12)	G. J. St Pé

		For	Against	Abstain
2.	RATIFICATION OF THE APPOINTMENT OF DELOITTE & TOUCHE LLP AS THE COMPANY'S INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2009	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.	STOCKHOLDER PROPOSAL ON ENVIRONMENTAL REPORT	0	0	0
6.	STOCKHOLDER PROPOSAL ON PENSION POLICY	0	0	0

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

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

If you desire to cumulate your votes and cast all of them for any individual nominee or distribute your votes in any manner, please check this box and write it on the reverse where indicated.


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

Admission Ticket

(Not Transferable)

2009 Annual Meeting of Stockholders

10 a.m. ET, May 27, 2009

(SOUTHERN COMPANY LOGO)

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 2009 Notice and Proxy Statement are available at www.proxyvote.com.

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M11947

FORM OF PROXY OR

TRUSTEE VOTING INSTRUCTION FORM

FORM OF PROXY OR

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 27, 2009, 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 ESP 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 or 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 25, 2009. The deadline for receipt of shares of record voted through the Form of Proxy is 9:00 a.m. on Wednesday, May 27, 2009. The deadline for receipt of instructions provided electronically is 11:59 p.m. on Tuesday, May 26, 2009.

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 OR 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.

CUMULATIVE VOTING -If you exercise cumulative voting, please check the box on the reverse side.

NAME OF CANDIDATE	# OF VOTES CAST	NAME OF CANDIDATE	# OF VOTES CAST
___________________________________	_______________	___________________________________	_______________
___________________________________	_______________	___________________________________	_______________
___________________________________	_______________	___________________________________	_______________
___________________________________	_______________	___________________________________	_______________
___________________________________	_______________	___________________________________	_______________
___________________________________	_______________	___________________________________	_______________