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

(Name of Registrant as Specified In Its Charter)

N/A

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TABLE OF CONTENTS

	Page
Letter to Stockholders
Notice of Annual Meeting of Stockholders of The Southern Company
Voting Information
Proxy Summary		i
Corporate Governance		1
*Item No. 1 – Election of Directors		1
*Item No. 2 – Approval of the Company’s Outside Directors Stock Plan		9
*Item No.  3 – Amendment to the Company’s By-Laws Related to the Ability of Stockholders to Act by Written Consent to Amend the By-Laws		9
Company Organization		10
Corporate Governance Website		11
Director Independence		11
Communicating with the Board		12
Stakeholder Engagement		12
Majority Voting for Directors		13
Political Contributions Policy		13
Director Compensation		13
Director Deferred Compensation Plan		13
Director Compensation Table		14
Director Stock Ownership Guidelines		15
Board Leadership Structure		15
Lead Independent Director		15
Meetings of Non-Management Directors		16
Committees of the Board		16
Audit Committee		16
Compensation and Management Succession Committee		17
Finance Committee		18
Governance Committee		19
Nominees for Election to the Board		19
Nuclear/Operations Committee		20
Business Security Subcommittee		20
Board Risk Oversight		21
Director Attendance		21

	Page
Stock Ownership Table		22
Stock Ownership of Directors, Nominees, and Executive Officers		22
Stock Ownership of Certain Other Beneficial Owners		23
Executive Compensation		24
*Item No. 4 – Advisory Vote on Named Executive Officers’ Compensation		24
Index to Executive Compensation		25
Audit		71
*Item No. 5 – Ratification of Appointment of Independent Registered Public Accounting Firm		71
Audit Committee Report		71
Principal Independent Registered Public Accounting Firm Fees		72
*Stockholder Proposals		73
Other Information		79
Frequently Asked Questions		79
Section 16(a) Beneficial Ownership Reporting Compliance		81
Certain Relationships and Related Transactions		81
Appendix A – Outside Directors Stock Plan
Appendix B – Proposed Amendment to Section  46 of the Company’s Bylaws
Appendix C – Policy on Engagement of the Independent Auditor For Audit and Non-Audit Services
Appendix D – 2014 Annual Report

* To be voted on at the meeting.

LETTER TO STOCKHOLDERS

Dear Fellow Stockholder:

You are invited to attend the 2015 Annual Meeting of Stockholders at 10 a.m. ET on Wednesday, May 27, 2015, at The Lodge Conference Center at Callaway Gardens, Pine Mountain, Georgia.

Your vote is important. Whether or not you plan to attend the meeting, please review the proxy material and vote by internet, phone, or mail as soon as possible.

At the annual meeting, I will report on our accomplishments from 2014, as well as our plans for 2015 and beyond. We will also elect our Board of Directors and vote on the other matters described in this Proxy Statement.

Throughout the entire 103-year history of The Southern Company, customers have always been at the center of all we do. This customer-focused business model continues to inform the decisions we make as we consider how our actions will potentially benefit the families, businesses, and communities we serve. Going forward, we will remain grounded in this core value.

This Proxy Statement includes Appendix D, the 2014 Annual Report with The Southern Company’s audited financial statements and management’s discussion and analysis of results of operation and financial condition.

We look forward to seeing you on May 27th. Thank you for your continued support of The Southern Company.

/s/ Thomas A. Fanning

Thomas A. Fanning

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS OF THE SOUTHERN COMPANY

DATE:	Wednesday, May 27, 2015
TIME:	10:00 a.m., ET
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. To elect 15 Directors;

2. To approve The Southern Company Outside Directors Stock Plan;

3. To approve an amendment to the By-Laws related to the ability of stockholders to act by written consent to amend the By-Laws;

4. To approve on a non-binding advisory basis The Southern Company’s named executive officers’ compensation;

5. To ratify the appointment of Deloitte & Touche LLP as The Southern Company’s independent registered public accounting firm for 2015;

6. To consider a stockholder proposal on proxy access;

7. To consider a stockholder proposal on greenhouse gas emissions reduction goals; and

8. To transact any other business properly coming before the meeting or any adjournments thereof.

RECORD DATE

Stockholders of record at the close of business on March 30, 2015 are entitled to attend and vote at the meeting. On that date, there were 908,996,758 shares of common stock (Common Stock) of The Southern Company (Southern Company or the Company) outstanding and entitled to vote.

ANNUAL REPORT TO STOCKHOLDERS

Appendix D to this Proxy Statement is The Southern Company’s 2014 Annual Report.

By Order of the Board of Directors,

Melissa K. Caen, Corporate Secretary,

April 10, 2015

VOTING INFORMATION

Even if you plan to attend the meeting in person, please provide your voting instructions as soon as possible by internet, by phone using the toll-free number, or by mail by marking, signing, dating, and returning the proxy form in the enclosed, postage-paid envelope.

Voting by the internet or by phone is fast and convenient, and your vote is immediately confirmed and tabulated.

PROXY VOTING OPTIONS

YOUR VOTE IS IMPORTANT!

Voting early will ensure the presence of a quorum at the meeting and may save The Southern Company the expense and extra work of additional solicitation.

VOTE BY INTERNET    

www.proxyvote.com

24 hours a day/7 days a week

Instructions:

Read this Proxy Statement

Go to the following website:

www.proxyvote.com

Have your proxy form or voting instruction

form in hand and follow the instructions.

VOTE BY PHONE    

1-800-690-6903

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

Instructions:

Read this Proxy Statement

Have your proxy form or voting instruction

form in hand and follow the instructions.

Please do not return the enclosed

paper ballot if you are voting by

internet or phone.

Important Notice Regarding the Availability of Proxy Materials for the 2015 Annual Meeting of Stockholders to be held on May 27, 2015:

The Company’s 2015 Proxy Statement, which includes the 2014 Annual Report as an appendix, is also available free of charge on the Company’s website at http://investor.southerncompany.com/proxy.

The Company’s 2014 Annual Report filed with the Securities and Exchange Commission (SEC) on Form 10-K will be provided without charge upon written request to Melissa K. Caen, Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.

PROXY SUMMARY

This summary highlights information contained elsewhere in this Proxy Statement. This summary does not contain all of the information that you should consider, and you should read the entire Proxy Statement carefully before voting.

MEETING AGENDA

Stockholders are being asked to vote on the following matters at the 2015 Annual Meeting of Stockholders (2015 Annual Meeting):

	The Board’s Recommendation
Item 1. Election of 15 Directors (page 1) Each nominee holds or has held senior executive positions, maintains the highest degree of integrity and ethical standards, and complements the needs of the Company. Through their positions, responsibilities, skills, and perspectives, which span various industries and organizations, these nominees represent a Board that is diverse and possesses appropriate collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and the Company’s industry and subsidiaries’ service territories.	For each Director nominee
Item 2. Approve The Southern Company Outside Directors Stock Plan (page 9) The Board of Directors has adopted effective June 1, 2015, subject to stockholder approval, the Outside Directors Stock Plan for Directors of The Southern Company and its Subsidiaries. The purpose of the Outside Directors Stock Plan is to provide a mechanism for non-employee Directors to automatically increase their ownership of Common Stock and thereby further align their interests with those of the Company’s stockholders.	For
Item 3. Approve Amendment to the By-Laws Related to the Ability of Stockholders to Act by Written Consent to Amend the By-Laws (page 9) The Board of Directors has determined that it is in the best interests of the Company and its stockholders to amend the Company’s By-Laws to permit stockholders to take action to amend the By-Laws without a meeting by the written consent of holders of not less than the minimum number of the issued and outstanding shares that would be necessary to take such action at a meeting at which all shares entitled to vote thereon were present and voted.	For
Item 4. Advisory Vote on Named Executive Officers’ Compensation (page 24) The Company believes its compensation program provides the appropriate mix of fixed and short- and long-term performance-based compensation that rewards achievement of the Company’s financial success, business unit financial and operational success, and total shareholder return. The Company seeks a non-binding advisory vote from its stockholders to approve the compensation of its named executive officers.	For
Item 5. Ratification of Independent Auditor for 2015 (page 71) The Audit Committee has appointed Deloitte & Touche LLP (Deloitte & Touche) as the Company’s independent registered public accounting firm for 2015. This appointment is being submitted to stockholders for ratification, and the Audit Committee and the Board of Directors believe that the continued retention of Deloitte & Touche to serve as the Company’s independent registered public accounting firm is in the best interests of the Company and its stockholders.	For
Item 6. Stockholder Proposal on Proxy Access, if properly presented (page 73) Proxy access is an untested governance feature for U.S. companies and it should not be implemented in the absence of a compelling rationale. The proponent’s proxy access proposal does not seek to remedy any specific governance or performance deficiency at the Company. The Company already has significant corporate governance practices that protect stockholder rights and interests. Implementing proxy access on the terms of this proposal could negatively affect the Company’s corporate governance.	Against
Item 7. Stockholder Proposal on Greenhouse Gas Emissions Reduction Goals, if properly presented (page 76) The Board of Directors does not believe it is in the best interests of the Company or its stockholders to independently establish at this time voluntary, absolute quantitative goals for reducing total greenhouse gas emissions from the Southern Company system’s operations. A separate report as requested in the proposal regarding plans to achieve such goals would not be an efficient use of additional Company resources or add value to the Company’s current efforts in this area.	Against

QUESTIONS AND ANSWERS ABOUT THE 2015 ANNUAL MEETING

Please review “Frequently Asked Questions” on page 79 for answers to common questions about the 2015 Annual Meeting.

  SOUTHERN COMPANY  i

KEY CORPORATE GOVERNANCE FEATURES

Southern Company seeks to establish corporate governance standards and practices that will be of value to long-term stockholders and create positive influences in the governance of the Company. Several of our key governance standards and practices include:

¡ Annual election of Directors

¡ Majority voting for Directors, with a Director resignation policy

¡ 10% threshold for stockholders to request a special meeting

¡ 14 of 15 Directors are independent

¡ Strong Lead Independent Director

¡ Annual Board and committee self-evaluations

¡ Proactive stockholder engagement

RECENT GOVERNANCE ENHANCEMENTS

¡ Established Business Security Subcommittee of the Board…see page 20

¡ Increased Stakeholder Engagement Efforts…see page 12

¡ Added Former U.S. Deputy Attorney General Larry D. Thompson to the Board…see page 8

¡ Added Alabama Business and Civic Leader John D. Johns to the Board…see page 6

¡ Enhanced the Responsibilities of the Lead Independent Director…see page 15

¡ Refreshed the Composition of Key Board Committees...see pages 16 to 20

ii  SOUTHERN COMPANY

EXECUTIVE COMPENSATION SUMMARY

Performance and Pay

Performance-based pay represents a substantial portion of the total direct compensation paid or granted to the named executive officers for 2014.

(1) Salary is the actual amount paid in 2014, Short-Term Performance Pay is the actual amount earned in 2014 based on performance, and Long-Term Performance Pay is the value on the grant date of stock options and performance shares granted in 2014. See the Summary Compensation Table for the amounts of all elements of reportable compensation described in the Compensation Discussion and Analysis. Information is provided for named executive officers serving at the end of 2014.

Compensation and Benefit Beliefs and Practices

The Company’s compensation and benefit program is based on the following beliefs:

¡ Employees’ commitment and performance have a significant impact on achieving business results;

¡ Compensation and benefits offered must attract, retain, and engage employees and must be financially sustainable;

¡ Compensation should be consistent with performance: higher pay for higher performance and lower pay for lower performance; and

¡ Both business drivers and culture should influence the compensation and benefit program.

Based on these beliefs, the Compensation Committee believes that the Company’s executive compensation program should:

¡ Be competitive with the Company’s industry peers;

¡ Motivate and reward achievement of the Company’s goals;

¡ Be aligned with the interests of the Company’s stockholders and its subsidiaries’ customers; and

¡ Not encourage excessive risk-taking.

  SOUTHERN COMPANY  iii

Executive compensation is targeted at the market median of industry peers, but actual compensation is primarily determined by achievement of the Company’s business goals. The Company believes that focusing on the customer drives achievement of financial objectives and delivery of a premium, risk-adjusted total shareholder return for the Company’s stockholders. Therefore, short-term performance pay is based on achievement of the Company’s operational and financial performance goals, with one-third determined by operational performance, such as safety, reliability, and customer satisfaction; one-third determined by business unit financial performance; and one-third determined by Company earnings per share performance. Long-term performance pay is tied to stockholder value, with 40% of the target value awarded in stock options, which reward stock price appreciation, and 60% awarded in performance shares, which reward total shareholder return performance relative to that of industry peers and stock price appreciation.

KEY COMPENSATION PRACTICES

WHAT WE DO

Annual pay risk assessment

Independent compensation consultant

Claw-back provision

Strong stock ownership requirements

WHAT WE DON’T DO

“No-hedging” provision in insider trading policy

No excise tax gross-ups on change-in-control severance arrangements

Limited ongoing perquisites

iv  SOUTHERN COMPANY

CORPORATE GOVERNANCE

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 2016 Annual Meeting of Stockholders.

The Board of Directors, acting upon the recommendation of the Governance Committee, nominates the following individuals for election to the Southern Company Board of Directors. Each nominee holds or has held senior executive positions, maintains the highest degree of integrity and ethical standards, and complements the needs of the Company. Through their positions, responsibilities, skills, and perspectives, which span various industries and organizations, these nominees represent a Board that is diverse and possesses appropriate collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and the Company’s industry and subsidiaries’ service territories, as detailed below.

Juanita Powell Baranco

	Age: 66 Director since: 2006 Board committee: Audit Principal occupation: Executive Vice President and Chief Operating Officer of Baranco Automotive Group, automobile sales Other public company directorships: None (formerly a Director of Cox Radio, Inc. and Georgia Power Company)
Director biography: Ms. Baranco had a successful legal career, which included serving as Assistant Attorney General for the State of Georgia, before she and her husband founded the first Baranco dealership in Atlanta in 1978. She served as a Director of Georgia Power Company (Georgia Power), the largest subsidiary of the Company, from 1997 to 2006. During her tenure on the Georgia Power Board, she was a member of the Controls and Compliance, Diversity, Executive, and Nuclear Operations Overview Committees. She served on the Federal Reserve Bank of Atlanta Board for a number of years and also on the Boards of Directors of John H. Harland Company and Cox Radio, Inc. An active leader in the Atlanta community, she serves on the Board of Trustees for Clark Atlanta University and on the Advisory Council for the Catholic Foundation of North Georgia, the Commerce Club, and the Woodruff Arts Center. She is also past Chair of the Board of Regents for the University System of Georgia and past Board Chair for the Sickle Cell Foundation of Georgia.
The Board has benefited from Ms. Baranco’s particular expertise in business operations and her civic involvement.

  SOUTHERN COMPANY  1

Jon A. Boscia

	Age: 62 Director since: 2007 Board committee: Audit (Chair) Principal occupation: Founder and President, Boardroom Advisors LLC, board governance consulting firm Other public company directorships: None (formerly a Director of PHH Corporation, Sun Life Financial Inc., Armstrong World Industries, Lincoln Financial Group, Georgia Pacific Corporation, and The Hershey Company)
Director biography: From September 2008 until March 2011, Mr. Boscia served as President of Sun Life Financial Inc. In this capacity, Mr. Boscia managed a portfolio of the company’s operations with ultimate responsibility for the United States, United Kingdom, and Asia business groups and directed the global marketing and investment management functions. Previously, Mr. Boscia served as Chairman of the Board and Chief Executive Officer of Lincoln Financial Group, a diversified financial services organization, until his retirement in 2007. Mr. Boscia became the Chief Executive Officer of Lincoln Financial Group in 1998. During his time at Lincoln Financial Group, the company earned a reputation for its stellar performance in making major acquisitions. Mr. Boscia is a past member of the Board of PHH Corporation, where he was Chair of the Audit Committee and a member of the Regulatory Oversight Committee, past member of the Board of Sun Life Financial Inc., where he was a member of the Investment Oversight Committee and the Risk Review Committee, and past member of the Board of The Hershey Company, where he chaired the Corporate Governance Committee and served on the Executive Committee. In addition, Mr. Boscia has served in leadership positions on other public company boards as well as not-for-profit and industry boards.
Mr. Boscia’s extensive background in finance, investment management, information technology, and corporate governance are valuable to the Board.

Henry A. “Hal” Clark III

	Age: 65 Director since: 2009 Board committees: Compensation and Management Succession (Chair), Finance Principal occupation: Senior Advisor of Evercore Partners Inc. (formerly Lexicon Partners, LLC), corporate finance advisory firm, since July 2009 Other public company directorships: None
Director biography: As a Senior Advisor with Evercore Partners Inc. (formerly Lexicon Partners, LLC), Mr. Clark is primarily focused on expanding advisory activities in North America with a particular focus on the power and utilities sectors. With more than 30 years of experience in the global financial and the utility industries, Mr. Clark brings a wealth of experience in finance and risk management to his role as a Director. Prior to joining Evercore Partners Inc., Mr. Clark was Group Chairman of Global Power and Utilities at Citigroup, Inc. from 2001 to 2009. His work experience includes numerous capital markets transactions of debt, equity, bank loans, convertible securities, and securitization, as well as advice in connection with mergers and acquisitions. He also has served as policy advisor to numerous clients on capital structure, cost of capital, dividend strategies, and various financing strategies. He has served as Chair of the Wall Street Advisory Group of the Edison Electric Institute.
Mr. Clark’s utility global financial and utility industry expertise as well as his expertise in capital market transactions are valuable to the Board.

2  SOUTHERN COMPANY

Thomas A. Fanning

	Age: 58 Director since: 2010 Principal occupation: Chairman of the Board, President, and Chief Executive Officer of the Company since December 2010 Other public company directorships: Vulcan Materials Company
Director biography: Mr. Fanning has held numerous leadership positions across the Southern Company system during his more than 30 years with the Company. He served as Executive Vice President and Chief Operating Officer of the Company from 2008 to 2010, leading the Company’s generation and transmission, engineering, and construction services, research and environmental affairs, system planning, and competitive generation business units. He served as the Company’s Executive Vice President and Chief Financial Officer from 2007 to 2008 and Executive Vice President, Chief Financial Officer, and Treasurer from 2003 to 2007, where he was responsible for the Company’s accounting, finance, tax, investor relations, treasury, and risk management functions. In those roles, he also served as the chief risk officer and had responsibility for corporate strategy. Mr. Fanning is on the Board of Southern Power Company (Southern Power), a subsidiary of Southern Company. Mr. Fanning is also a Director of Vulcan Materials Company, serving as a member of the Audit Committee and the Compensation Committee, and the Federal Reserve Bank of Atlanta, serving as Chairman of the Board. Mr. Fanning served on the Board of The St. Joe Company from 2005 through September 2011.
Mr. Fanning’s knowledge of the Company’s business and the electric utility industry, understanding of the complex regulatory structure of the industry, and experience in strategy development and execution uniquely qualify him to be the Chairman of the Board.

David J. Grain

	Age: 52 Director since: 2012 Board committees: Compensation and Management Succession, Finance Principal occupation: Founder and Managing Partner, Grain Management, LLC, private equity firm Other public company directorships: None
Director biography: Mr. Grain is the founding member and managing partner of Grain Management LLC (Grain Management), a private equity firm focused on investments in the media and communications sectors, which he founded in 2006. With offices in Sarasota, Florida and Washington, D.C., the firm manages funds for a number of the country’s leading academic institutions, endowments, and public pension funds. Grain Management also builds, owns, and operates wireless infrastructure assets across North America. Mr. Grain also founded and was Chief Executive Officer of Grain Communications Group, Inc. Prior to Grain Management, he served as President of Global Signal, Inc., Senior Vice President of AT&T Broadband’s New England Region, and Executive Director in the High Yield Finance Department at Morgan Stanley. Mr. Grain was appointed by President Obama in 2011 to the National Infrastructure Advisory Council. He previously served as chairman of the Florida State Board of Administration Investment Advisory Council as an appointee of the former Governor Charlie Crist. He is currently a Director at Gateway Bank of Southwest Florida, a Trustee of the College of the Holy Cross, and serves on the Investment Committee of the United States Tennis Association.
Mr. Grain’s background in finance, investment management, and wireless communications infrastructure, leadership, and civic involvement are valuable to the Board.

  SOUTHERN COMPANY  3

Veronica M. Hagen

	Age: 69 Director since: 2008; Lead Independent Director since May 28, 2014 Board committees: Compensation and Management Succession, Nuclear/Operations Other public company directorships: Polymer Group, Inc., Newmont Mining Corporation
Director biography: From 2007 until her retirement in 2013, Ms. Hagen served as Chief Executive Officer of Polymer Group, Inc., where she continues to serve as a Director and Chair of the Nominating and Corporate Governance Committee. Ms. Hagen also served as President of Polymer Group, Inc. from January 2011 until her retirement in 2013. Polymer Group, Inc. is a leading producer and marketer of engineered materials. Prior to joining Polymer Group, Inc., Ms. Hagen was the President and Chief Executive Officer of Sappi Fine Paper, a division of Sappi Limited, the South African-based global leader in the pulp and paper industry, from November 2004 until 2007. She also has served as Vice President and Chief Customer Officer at Alcoa Inc. and owned and operated Metal Sales Associates, a privately-held metal business. Ms. Hagen also serves as the Chair of the Compensation Committee and a member of the Environmental, Social Responsibility, and Safety Committee of the Board of Newmont Mining Corporation.
Ms. Hagen’s global operational management experience and commercial business leadership are valuable assets to the Board.

Warren A. Hood, Jr.

	Age: 63 Director since: 2007 Board committee: Audit Principal occupation: Chairman of the Board and Chief Executive Officer of Hood Companies, Inc., packaging and construction products Other public company directorships: BancorpSouth, Inc. (formerly a Director of Mississippi Power Company)
Director biography: Mr. Hood is the Chairman and Chief Executive Officer of Hood Companies Inc. which he established in 1978. Hood Companies Inc. consists of four separate corporations with 60 manufacturing and distribution sites throughout the United States, Canada, and Mexico. Hood Companies, Inc.’s products are currently marketed in North America, the Caribbean, and Western Europe. Mr. Hood previously served on the Board of the Company’s subsidiary, Mississippi Power Company (Mississippi Power), where he was also a member of the Compensation Committee. Mr. Hood has long been recognized for his leadership role in the State of Mississippi. He serves or has served on numerous corporate, community, and philanthropic boards, including Boy Scouts of America Pine Burr Area Council, Governor Phil Bryant’s Mississippi Works Committee, and The Governor’s Commission on Rebuilding, Recovery and Renewal, which was formed following Hurricane Katrina in 2005. He serves on the Board of BancorpSouth, Inc., where he is a member of the Audit Committee.
Mr. Hood’s business operations, risk management, and financial experience and civic involvement are valuable to the Board.

4  SOUTHERN COMPANY

Linda P. Hudson

	Age: 64 Director since: 2014 Board committees: Governance, Nuclear/Operations, Business Security Subcommittee Principal Occupation: Founder, Chairman, and Chief Executive Officer, The Cardea Group, business management consulting firm Other public company directorships: BAE Systems, Inc., Bank of America Corporation
Director biography: Ms. Hudson is the Founder, Chairman, and Chief Executive Officer of The Cardea Group, a business management consulting firm she founded in 2014. From October 2009 through February 2014, Ms. Hudson served as the President and Chief Executive Officer of BAE Systems, Inc. (BAE Systems), a U.S.-based global defense, aerospace, and security company. BAE Systems is a wholly-owned subsidiary of London-based BAE Systems plc. Previously, Ms. Hudson served as President of BAE Systems’ Land & Armaments operating group, the world’s largest military vehicle and equipment business. Before joining BAE Systems in 2006, she served as Vice President of the General Dynamics Corporation and President of General Dynamics Armament and Technical Products. She currently serves as an adviser and outside Director for BAE Systems. She is also a member of Bank of America Corporation’s Board of Directors, where she serves on the Compensation and Benefits Committee and the Credit Committee. She is also a Director of the University of Florida Foundation and a Director of the Center for a New American Security.
Ms. Hudson’s experience leading a large, highly-regulated, complex business and expertise in engineering, technology, operations, and risk management are valuable to the Board.

Donald M. James

	Age: 66 Director since: 1999 Board committees: Governance (Chair), Finance Other public company directorships: Vulcan Materials Company, Wells Fargo & Company (formerly a Director of Protective Life Corporation)
Director biography: Mr. James retired from his position as Chief Executive Officer of Vulcan Materials Company in July 2014 and Executive Chairman in January 2015. He continues to serve as Chairman of the Board of Directors of Vulcan Materials Company. Mr. James joined Vulcan Materials Company in 1992 as Senior Vice President and General Counsel and then became President of the Southern Division and then Senior Vice President of the Construction Materials Group and President and Chief Executive Officer. Prior to joining Vulcan Materials Company, Mr. James was a partner at the law firm of Bradley, Arant, Rose & White for 10 years. Mr. James is also a Trustee of the UAB Health System and Children’s of Alabama, where he serves on the Executive Committee. In addition, he serves on the Finance and the Human Resources Committees of Wells Fargo & Company’s Board of Directors.
Mr. James’ leadership of a large public company, his legal expertise, and his civic involvement are valuable assets to the Board.

  SOUTHERN COMPANY  5

John D. Johns

	Age: 63 Director since: 2015 Board committees: Audit Principal occupation: Chairman, President, and Chief Executive Officer of Protective Life Corporation (Protective Life) Other public company directorships: Regions Financial Corporation, Genuine Parts Company (formerly a Director of Alabama Power Company)
Director biography: Mr. Johns has served as Chairman, President, and Chief Executive Officer of Protective Life since 2002. He joined Protective Life in 1993 as Executive Vice President and Chief Financial Officer. Before his tenure at Protective Life, Mr. Johns served as general counsel of Sonat, Inc., a diversified energy company. Prior to joining Sonat, Inc., Mr. Johns was a founding partner of the law firm Maynard Cooper & Gale. He previously served on the Board of Directors of Alabama Power Company (Alabama Power) from 2004 to 2015. During his tenure on the Alabama Power Board, he was a member of the Nominating Committee and Executive Committee. Mr. Johns has served on the Executive Committee of the Financial Services Roundtable in Washington, D.C., and is the immediate past chairman of the American Council of Life Insurers. He is a member of the Board of Directors of Regions Financial Corporation, where he serves on the Nominating and Governance and Risk Committees, and Genuine Parts Company, where he serves on the Compensation, Nominating and Governance Committee. Mr. Johns has served as the Chairman of the Business Council of Alabama, the Birmingham Business Alliance, the Greater Alabama Council, Boy Scouts of America, and Innovation Depot, Alabama’s leading business and technology incubator.
Mr. Johns’ management and leadership experience, his significant familiarity with Alabama Power, and his civic involvement are valuable to the Board.

Dale E. Klein

	Age: 67 Director since: 2010 Board committees: Governance, Nuclear/Operations, Business Security Subcommittee (Chair) Principal occupation: Associate Vice Chancellor of Research of the University of Texas System since 2011 and Associate Director of the Energy Institute at The University of Texas at Austin since 2010 Other public company directorships: Pinnacle West Capital Corporation, Arizona Public Service Company
Director biography: Dr. Klein was Commissioner from 2009 to 2010 and Chairman from 2006 through 2009 of the U.S. Nuclear Regulatory Commission. Dr. Klein also served as Assistant to the Secretary of Defense for Nuclear, Chemical, and Biological Defense Programs from 2001 through 2006. Dr. Klein has more than 35 years of experience in the nuclear energy industry. Dr. Klein began his career at the University of Texas in 1977 as a professor of mechanical engineering which included a focus on the university’s nuclear program. He spent nearly 25 years in various teaching and leadership positions including Director of the nuclear engineering teaching laboratory, associate dean for research and administration in the College of Engineering, and vice-chancellor for special engineering programs. He serves on the Audit and Nuclear and Operating Committees of Pinnacle West Capital Corporation, an Arizona energy company, and is a member of the Board of Pinnacle West Capital Corporation’s principal subsidiary, Arizona Public Service Company.
Dr. Klein’s expertise in nuclear energy regulation and operations, technology, and safety is valuable to the Board.

6  SOUTHERN COMPANY

William G. Smith, Jr.

	Age: 61 Director since: 2006 Board committees: Finance (Chair), Compensation and Management Succession Principal occupation: Chairman of the Board, President, and Chief Executive Officer of Capital City Bank Group, Inc., banking Other public company directorships: Capital City Bank Group, Inc.
Director biography: Mr. Smith began his career at Capital City Bank in 1978, where he worked in a number of positions of increasing responsibility before being elected President and Chief Executive Officer of Capital City Bank Group, Inc. in January 1989. He was elected Chairman of the Board of the Capital City Bank Group, Inc. in 2003. He is also the Chairman and Chief Executive Officer of Capital City Bank. He previously served on the Board of Directors of the Federal Reserve Bank of Atlanta. He is the former Federal Advisory Council Representative for the Sixth District of the Federal Reserve System and past Chair of both Tallahassee Memorial HealthCare and the Tallahassee Area Chamber of Commerce.
Mr. Smith’s experience in finance, business operations, and risk management is valuable to the Board.

Steven R. Specker

	Age: 69 Director since: 2010 Board committees: Nuclear/Operations (Chair), Compensation and Management Succession Other public company directorships: Trilliant Incorporated
Director biography: Dr. Specker served as President and Chief Executive Officer of the Electric Power Research Institute (EPRI) from 2004 until his retirement in 2010. Prior to joining EPRI, Dr. Specker founded Specker Consulting, LLC, a private consulting firm, which provided operational and strategic planning services to technology companies serving the global electric power industry. Dr. Specker also served in a number of leadership positions during his 30-year career at General Electric Company (GE), including serving as President of GE’s nuclear energy business, President of GE digital energy, and Vice President of global marketing. Dr. Specker is also a member of the Board of Trilliant Incorporated, a leading provider of Smart Grid communication solutions.
Dr. Specker brings to the Board a keen understanding of the electric industry and valuable insight in innovation and technology development.

  SOUTHERN COMPANY  7

Larry D. Thompson

	Age: 69 Director since: 2014 (previously served from 2010 to 2012) Board committee: Audit Other public company directorships: Franklin, Templeton Series Mutual Funds, Graham Holdings Company (formerly a Director of Cbeyond, Inc.)
Director biography: From 2012 until his retirement in 2014, Mr. Thompson served as Executive Vice President, Government Affairs, General Counsel, and Corporate Secretary for PepsiCo Inc., one of the world’s largest packaged food and beverage companies. Prior to that, Mr. Thompson served from 2004 to 2011 as Senior Vice President of Government Affairs, General Counsel, and Corporate Secretary of PepsiCo Inc. In his role at PepsiCo Inc., Mr. Thompson was responsible for PepsiCo Inc.’s worldwide legal function, as well as its government affairs organization, and the company’s charitable foundation. His government career includes serving as Deputy Attorney General in the United States Department of Justice and leading the National Security Coordination Council. In 2002, President George W. Bush named Mr. Thompson to head the Department of Justice’s Corporate Fraud Task Force. Mr. Thompson is an Independent Trustee of various investment companies in the Franklin Templeton group of mutual funds and a Director and a member of the Compensation Committee of Graham Holdings Company (formerly The Washington Post Company). He also serves as a Director of the PepsiCo Foundation. Mr. Thompson served as a Director of Southern Company from 2010 to 2012 and was a member of the Audit Committee.
Mr. Thompson’s government experience and corporate governance and legal expertise are valuable to the Board.

E. Jenner Wood III

	Age: 63 Director since: 2012 Board committees: Governance, Nuclear/Operations Principal occupation: Chairman and Chief Executive Officer of the Atlanta Division of SunTrust Bank and Corporate Executive Vice President of SunTrust Banks, Inc., banking Other public company directorships: Genuine Parts Company, Oxford Industries, Inc. (formerly a Director of Crawford & Company and Georgia Power)
Director biography: Mr. Wood is currently the Chairman, President, and Chief Executive Officer of the Atlanta Division of SunTrust Bank, a position he has held since April 2014, where he is responsible for managing retail, commercial, and private wealth banking in the Greater Atlanta area. He also has served as an Executive Vice President of SunTrust Banks, Inc. since July 2005. From April 2010 through January 2013, he was Chairman of the Board, President, and Chief Executive Officer of the Atlanta/Georgia Division of SunTrust Bank and from January 2013 through March 2014 he was Chairman of the Board, President, and Chief Executive Officer of the Georgia/North Florida Division of SunTrust Bank. From 2002 through 2010, he served as Chairman, President, and Chief Executive Officer of SunTrust Bank Central Group with responsibility over Georgia and Tennessee. He served as a member of the Board of Georgia Power from 2002 until May 2012. During his tenure on the Georgia Power Board, he served as a member of the Compensation, Executive, and Finance Committees. Mr. Wood is a Director of Oxford Industries, Inc., where he serves as Presiding Director and as a member of the Executive Committee, and a Director of Genuine Parts Company, where he serves on the Audit Committee. He is active in numerous civic and community organizations, serving as a Trustee of the Robert W. Woodruff Foundation, The Sartain Lanier Family Foundation, Camp-Younts Foundation, the Jesse Parker Williams Foundation, and the William I. H. and Lula E. Pitts Foundation.
Mr. Wood’s leadership experience and extensive background in finance as well as his involvement in the community are beneficial to the Board.

8  SOUTHERN COMPANY

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 majority of the votes cast is required for the election of Directors at any meeting for the election of Directors at which a quorum is present. 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.

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

ITEM NO. 2 — APPROVAL OF THE COMPANY’S OUTSIDE DIRECTORS STOCK PLAN

The Board of Directors has adopted effective June 1, 2015, subject to stockholder approval, the Outside Directors Stock Plan for Directors of The Southern Company and its Subsidiaries (Plan). The purpose of the Plan is to provide a mechanism for non-employee Directors to automatically increase their ownership of Common Stock and thereby further align their interests with those of the Company’s stockholders.

The Plan will be administered by the Company’s Governance Committee.

The Plan provides for the payment to non-employee Directors of a portion of their annual retainer fee in unrestricted shares of Common Stock. For the subsidiary company participants, the equity-based annual retainer fee that will be payable under the Plan in Common Stock ranges from $19,500 to $30,000 per year. See “Director Compensation” in this Proxy Statement for a description of the equity-based annual retainer fee paid to the Company’s Directors. Additionally, the Plan permits participants to elect to receive a greater portion — up to all — of their Director compensation in Common Stock. For the Company’s Directors, the receipt of Common Stock under the Plan is deferred until departure from the Board of Directors. Other subsidiary company participants may elect

to defer receipt of all or a portion of Common Stock paid under the Plan until departure from their respective Board of Directors. The Company expects that there will be approximately 55 Company and subsidiary company Directors initially participating in the Plan.

The maximum amount of Common Stock that may be granted under the Plan is 1,000,000 shares.

The Board of Directors of the Company may amend or terminate the Plan at any time, subject to any required stockholder approval. The maximum amount of Common Stock that may be granted under the Plan may not be increased without stockholder approval.

The estimated amount to be paid to the Company’s non-executive Directors as a group under the Plan in 2015 is $3.5 million. The actual number of shares of Common Stock to be received will be dependent upon the market price of the Common Stock on the date of grant. No amounts will be paid to executive officers or other employees under the Plan.

The text of the Plan is included as Appendix A to this Proxy Statement.

The affirmative vote of a majority of the votes cast is required for approval of the Plan.

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

ITEM NO. 3 — AMENDMENT TO THE COMPANY’S BY-LAWS RELATED TO THE ABILITY OF STOCKHOLDERS TO ACT BY WRITTEN CONSENT TO AMEND THE BY-LAWS

The Board of Directors has determined that it is in the best interests of the Company and its stockholders to amend the provision contained in Section 46 of the Company’s By-Laws (By-Laws) relating to the ability of stockholders to act by written consent to amend the By-Laws. The proposed amendment would amend the By-Laws to permit stockholders to take action to amend the By-Laws without a meeting by the

  SOUTHERN COMPANY  9

written consent of holders of not less than the minimum number of the issued and outstanding shares that would be necessary to take such action at a meeting at which all shares entitled to vote thereon were present and voted.

Background of This Item

The Board of Directors is committed to implementing and maintaining effective corporate governance policies and practices which seek to ensure that the Company is governed with high standards of ethics, integrity, and accountability and in the best interest of the Company’s stockholders. A written consent right generally affords stockholders a means of acting between annual meetings other than by calling a special meeting. Under Section 228(a) of the Delaware General Corporation Law (DGCL), any action that may be taken at a meeting of stockholders may be taken without a meeting “by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted,” unless otherwise provided in the certificate of incorporation. The Company’s Certificate of Incorporation permits the Company’s stockholders to act by written consent because it does not restrict that right. The only provision in the By-Laws that concerns stockholders’ ability to act by written consent is contained in Section 46, which provides that stockholders may amend the By-Laws without a meeting but only by unanimous written consent. The Board of Directors has determined that revising this provision in the By-Laws to make it consistent with Section 228(a) of the DGCL and the Company’s Certificate of Incorporation is in the best interests of the Company and its stockholders.

As a result, the Board of Directors voted to approve, and to recommend to the Company’s stockholders that they approve, a proposal to amend Section 46 of the By-Laws to permit stockholders to take action to amend the By-Laws without a meeting by the written consent of holders of not less than the minimum number of the issued and outstanding shares of capital

stock of the Company having voting powers that would be necessary to take such action at a meeting at which all shares entitled to vote thereon were present and voted. Under the By-Laws, the proposed amendment to Section 46 of the By-Laws requires stockholder approval in order to become effective.

Amendment

The proposed amendment to Section 46 of the By-Laws would revise the provision that relates to the ability of stockholders to act by written consent to amend the By-Laws. If approved, this proposed amendment would conform Section 46 of the By-Laws to Section 228 of the DGCL and the Company’s Certificate of Incorporation to make clear that the standard set forth in Section 228(a) of the DGCL governs the ability of the Company’s stockholders to act by written consent.

The text of the proposed amendment, marked to show changes to the current Section 46 of the By-Laws, is included as Appendix B to this Proxy Statement.

The affirmative vote of a majority of the shares represented in person or by proxy and entitled to vote at the annual meeting is required for approval of the proposed amendment to Section 46 of the By-Laws as presented in this Item No. 3.

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

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 15 members.

At the 2015 Annual Meeting, stockholders will elect 15 Directors. The nominees for election as Directors consist of 14 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 Information for Investors/Corporate Governance.

10  SOUTHERN COMPANY

Corporate Governance Website

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

¡ Code of Ethics

¡ By-Laws

¡ Executive Stock Ownership Requirements

¡ Board Committee Charters

¡ Board of Directors — Background and Experience

¡ Management Council — Background and Experience

¡ Composition of Board Committees

¡ SEC filings

¡ Link for on-line communication with Board of Directors

¡ Political Spending and Lobbying-Related Activities

¡ Anti-Hedging Provision

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

Director Independence

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

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

¡ The Director has received, or the Director’s immediate family member has 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 service as a non-executive employee of the Company need not be considered.)

¡ The Director was affiliated with or employed by, or the Director’s immediate family member was affiliated with or employed in a professional capacity by, a present or former external auditor of the Company and personally worked on the Company’s audit.

¡ 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 executive officers at the same time served on that company’s compensation committee.

¡ 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 year, exceeds the greater of $1,000,000 or two percent of that company’s consolidated gross revenues.

¡ The Director or the Director’s spouse serves as an executive officer of a charitable organization to which the Company made discretionary contributions which, in any year, exceeds the greater of $1,000,000 or two percent of the organization’s consolidated gross revenues.

At least annually, the Board receives a report on 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 report specifically includes all ordinary course transactions with entities with which the Directors are associated. The Board determined that the Company and its subsidiaries followed

  SOUTHERN COMPANY  11

the Company’s procurement policies and procedures, that the amounts reported were well under the thresholds contained in the Director independence requirements, and that no Director had a direct or indirect material interest in the transactions. See Other Information — Certain Relationships and Related Transactions for a discussion of related party transactions identified by the Company.

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 other contributions by the Company and its subsidiaries to charitable organizations and none were approved outside the Company’s normal procedures.

At least annually, the Board also reviews Director independence. The Board considers transactions, if any, identified in the review of the report discussed above that affect Director independence, including any transactions in which the amounts reported were above the threshold contained in the Director independence requirements and in which a Director had a direct or indirect material interest. No such transactions were identified and, as a result, no such transactions were considered by the Board. In determining independence, the Board also considered that, in the ordinary course of the Southern Company system’s business, electricity is provided to some Directors and entities with which the Directors are associated on the same terms and conditions as provided to other customers of the Southern Company system.

As a result of its review of Director independence, the Board affirmatively determined that none of the following persons who are currently serving as Directors or who served during 2014 or who are nominees for election as Directors has a material relationship with the Company and, as a result, such persons are determined to be independent: Juanita Powell Baranco, Jon A. Boscia, Henry A. Clark III, David J. Grain, H. William Habermeyer, Jr., Veronica M. Hagen, Warren A. Hood, Jr., Linda P.

Hudson, Donald M. James, John D. Johns, Dale E. Klein, William G. Smith, Jr., Steven R. Specker, Larry D. Thompson, and E. Jenner Wood III. Thomas A. Fanning, a current Director, is Chairman of the Board, President, and Chief Executive Officer of the Company and is not independent.

Communicating with the Board

Interested parties may communicate directly with the Company’s Board or specified Directors, including the Lead Independent Director. Communications may be sent to the Company’s Board or to specified Directors, including the Lead Independent Director, by regular mail or electronic mail. Regular mail should be sent to the attention of Melissa K. Caen, 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 Information for Investors/Corporate Governance on the Company’s website at www.southerncompany.com, under the link entitled Governance Inquiries. With the exception of commercial solicitations, all communications directed to the Board or to specified Directors will be relayed to them.

Stakeholder Engagement

The Company places great importance on consistent dialogue with its stakeholders, including customers, investors, and employees as well as with the financial community generally. The Company also regularly engages in discussions with, and provides comprehensive information for, its constituents interested in the Southern Company system’s citizenship, stewardship, and environmental compliance. As part of these efforts, in 2014, the Company began a more systematic approach to investor outreach and involved members of its senior management and the Board of Directors. These efforts included a specific focus on the Company’s corporate governance philosophy and practices and its desire to hear about the governance topics of specific interest to its stockholders. Moving forward, the Company will

12  SOUTHERN COMPANY

continue to take an active, inclusive, and flexible approach to stakeholder engagement.

Majority Voting for Directors

Since 2010, the Company has had a majority vote standard for Director elections, which requires 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 this standard for uncontested elections is a more equitable standard than a plurality vote standard. A plurality vote standard guarantees the election of a Director in an uncontested election; however, a majority vote standard means that nominees in uncontested elections are only elected if a majority of the votes cast are voted in their favor. The Board believes that the majority vote standard in uncontested Director elections strengthens the Director nomination process and enhances Director accountability.

The Company also has a resignation policy, which requires any nominee for election as a Director 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.

Political Contributions Policy

The Board reviews the Company’s political contributions and its policies and procedures regarding political contributions. Any corporate political contributions or independent expenditures made by the Company and its subsidiaries in connection with elections for public office, as well as any payments made by the Company and its subsidiaries to other organizations that are designated for their use in making political contributions or independent expenditures, are reviewed at least annually with the Board. Any corporate contributions to ballot

initiative campaign committees also are reviewed annually with the Board.

Director Compensation

Only non-employee Directors of the Company are compensated for service on the Board of Directors. During 2014, the pay components for non-employee Directors were:

        Annual retainers:

¡ $100,000 cash retainer

¡ Additional $20,000 cash retainer if serving as a chair of a committee of the Board

¡ Additional $20,000 cash retainer if serving as the Lead Independent Director of the Board

        Annual equity grant:

¡ $120,000 in deferred Common Stock units until Board membership ends

        Meeting fees:

¡ 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.

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

On December 8, 2014, the Board of Directors created a Business Security Subcommittee of the Nuclear/Operations Committee and approved an additional $12,500 annual cash retainer for serving on such subcommittee.

Director Deferred Compensation Plan

The annual equity grant is required to be deferred in shares of Common Stock under the Deferred Compensation Plan for Outside Directors of The Southern Company, as amended and restated effective January 1, 2008 (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 or cash.

  SOUTHERN COMPANY  13

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 or cash upon leaving the Board; or

¡ at the prime interest rate which is paid in cash upon leaving the Board.

All investments and earnings in the Director Deferred Compensation Plan are fully vested and, at the election of the Director, may be distributed in a lump-sum payment, or in up to 10 annual distributions after leaving the Board. The Company has established a grantor trust that primarily holds Common Stock that funds the Common Stock units that are distributed in shares of 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 2014, 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. Mr. Johns, who was elected to the Board effective February 9, 2015, is not included in this table.

Name	Fees Earned or Paid in Cash ($) (1)		Stock Awards ($) (2)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)		All Other Compensation ($) (3)		Total ($)
Juanita Powell Baranco		116,667		120,000		—		—		—		1,502		238,169
Jon A. Boscia		120,000		120,000		—		—		—		1,499		241,499
Henry A. Clark III		111,667		120,000		—		—		—		1,723		233,390
David J. Grain		100,001		120,000		—		—		—		1,310		221,311
H. William Habermeyer, Jr. (4)		50,000		50,000		—		—		—		280		100,280
Veronica M. Hagen		120,000		120,000		—		—		—		1,453		241,453
Warren A. Hood, Jr.		100,001		120,000		—		—		—		1,443		221,444
Linda P. Hudson (5)		75,001		90,000		—		—		—		1,301		166,302
Donald M. James		111,667		120,000		—		—		—		1,647		233,314
Dale E. Klein		100,001		120,000		—		—		—		1,175		221,176
William G. Smith, Jr.		120,000		120,000		—		—		—		1,175		241,175
Steven R. Specker		111,667		120,000		—		—		—		1,559		233,226
Larry D. Thompson (6)		8,333		10,000		—		—		—		1,077		19,410
E. Jenner Wood III		100,001		120,000		—		—		—		1,675		221,676

(1) Includes amounts voluntarily deferred in the Director Deferred Compensation Plan.

(2) Represents the grant date fair market value of deferred Common Stock units.

(3) Consists of tax reimbursements for taxes on imputed income associated with gifts and activities provided to attendees at Company-sponsored events.

(4) Mr. Habermeyer retired from the Board effective May 28, 2014.

(5) Ms. Hudson was elected to the Board effective March 1, 2014.

(6) Mr. Thompson was elected to the Board effective December 1, 2014.

14  SOUTHERN COMPANY

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 five times the annual Director cash retainer fee. Also, as described in the Director Compensation section above, the annual equity grant received as a part of the annual compensation for non-employee Directors is required to be deferred until Board membership ends. All non-employee Directors either meet the stock ownership guideline or are expected to meet the guideline within the allowed timeframe.

Board Leadership Structure

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

The Board believes the combined role of Chief Executive Officer and Chairman, together with a strong Lead Independent Director having the duties described below, is in the best interest of stockholders because it provides the optimal

balance between independent oversight of management and unified leadership.

Lead Independent Director

The Lead Independent Director is elected every two years by the independent Directors. Non-management Directors meet, without management, on each regularly-scheduled Board meeting date, and at other times as deemed appropriate by the Lead Independent Director or two or more other independent Directors.

The Lead Independent Director has the following powers and responsibilities:

¡ approving the agenda and schedule for Board meetings and information sent to the Board;

¡ calling and chairing executive sessions of the non-management Directors;

¡ chairing Board meetings in the absence of the Chairman;

¡ meeting regularly with the Chairman;

¡ acting as the principal liaison between the Chairman and the non-management Directors (however, each Director has direct and complete access to the Chairman at any time);

¡ serving as the primary contact Director for stockholders and other interested parties; and

¡ communicating any sensitive issues to the Directors.

Ms. Veronica M. Hagen currently serves as the Company’s Lead Independent Director. Mr. William G. Smith, Jr. served as the Company’s Presiding Director effective May 23, 2012 until May 28, 2014. In February 2014, Ms. Hagen was appointed to serve as the Presiding Director effective May 28, 2014 until the Company’s 2016 Annual Meeting of Stockholders. On July 21, 2014, the Board of Directors approved an amendment to the Company’s Corporate Governance Guidelines changing the Presiding Director’s title to “Lead Independent Director” and enhancing the Lead Independent Director’s responsibilities, including noting that the Lead Independent Director

  SOUTHERN COMPANY  15

approves the agenda and schedule for Board meetings and information sent to the Board.

Meetings of Non-Management Directors

Non-management Directors meet in executive session without any members of the Company’s management present on each regularly-scheduled Board meeting date. These executive sessions promote an open discussion of matters in a manner that is independent of the Chairman

and Chief Executive Officer. The Lead Independent Director chairs each of these executive sessions.

Committees of the Board

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

Audit Committee

Jon A. Boscia Chair

Ø Current members are Mr. Boscia (Chair), Ms. Baranco,⁽¹⁾ Mr. Hood, Mr. Johns,⁽²⁾ and Mr. Thompson.⁽¹⁾

Ø Met ten times in 2014

Ø The Audit Committee’s duties and responsibilities, which are described in its charter, include the following:

¡ Oversee the Company’s financial reporting, audit processes, internal controls, and legal, regulatory, and ethical compliance.

¡ Appoint the Company’s independent registered public accounting firm, approve its services and fees, and establish and review the scope and timing of its audits.

¡ Review and discuss the Company’s financial statements with management, the internal auditors, 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.

¡ Recommend the filing of the Company’s and its registrant subsidiaries’ 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 (NYSE) 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. Boscia qualifies as an “audit committee financial expert” as defined by the SEC.

(1) Ms. Baranco and Mr. Thompson were appointed as members of the Audit Committee effective December 1, 2014.

(2) Mr. Johns was appointed a member of the Audit Committee effective March 1, 2015.

16  SOUTHERN COMPANY

Compensation and Management Succession Committee (Compensation Committee)

Henry A. “Hal” Clark III Chair

Ø Current members are Mr. Clark (Chair), Mr. Grain,⁽¹⁾ Ms. Hagen, Mr. Smith, and Dr. Specker.⁽²⁾

Ø Met seven times in 2014

Ø The Compensation Committee’s duties and responsibilities, which are described in its charter, include the following:

¡ Evaluate performance of executive officers and establish their compensation, administer executive compensation plans, and review management succession plans.

¡ Annually review a tally sheet of all components of the executive officers’ compensation and take actions required of it under the Pension Plan for employees of the Company’s subsidiaries.

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

(1) Mr. Grain was appointed as a member of the Compensation Committee effective December 1, 2014.

(2) Dr. Specker was appointed a member of the Compensation Committee effective May 28, 2014.

Committee Governance

During 2014, 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 independent compensation consultants;

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

¡ Reviewing a compensation risk assessment through a process developed by its independent compensation consultant.

Role of Executive Officers

The Chief Executive Officer, with input from the Company’s Human Resources staff, recommends to the Compensation Committee: base salary, target performance-based compensation levels, actual performance-based compensation payouts, and long-term performance-based 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 recommendations.

Role of Compensation Consultant

The Compensation Committee, which has authority to retain independent advisors, including compensation consultants, at the Company’s expense, engaged Pay Governance LLC (Pay Governance) to provide an independent assessment of the current executive compensation program and any management-recommended changes to that program and to

  SOUTHERN COMPANY  17

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 Pay Governance to advise on executive compensation and related corporate governance trends.

Pay Governance is engaged solely by the Compensation Committee and does not provide any services directly to management unless authorized to do so by the Compensation Committee. In connection with its engagement of Pay Governance, the Compensation Committee reviewed Pay Governance’s independence including (1) the amount of fees received by Pay Governance from the Company as a percentage of Pay Governance’s total revenue; (2) its policies and procedures designed to prevent conflicts of

interest; and (3) the existence of any business or personal relationships, including Common Stock ownership, that could impact independence. After reviewing these and other factors, the Compensation Committee determined that Pay Governance is independent and the engagement did not present any conflicts of interest. Pay Governance also determined that it was independent from management, which was confirmed in a written statement delivered to the Compensation Committee.

During 2014, Pay Governance assisted the Compensation Committee with analyzing comprehensive market data and its implications for pay at the Company and its affiliates and various other governance, design, and compliance matters.

Finance Committee

William G. Smith, Jr. Chair

Ø Current members are Mr. Smith (Chair), Mr. Clark, Mr. Grain,⁽¹⁾ and Mr. James

Ø Met seven times in 2014

Ø The Finance Committee’s duties and responsibilities, which are described in its charter, include the following:

¡ Review the Company’s financial matters and recommend actions such as dividend philosophy and financial plan approval to the Board.

¡ Provide input to the Compensation Committee regarding the Company’s financial plan and associated financial goals.

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

(1) Mr. Grain was appointed a member of the Finance Committee effective December 1, 2014.

18  SOUTHERN COMPANY

Governance Committee

Donald M. James Chair

Ø Current members are Mr. James (Chair), Ms. Hudson,⁽¹⁾ Dr. Klein, and Mr. Wood

Ø Met six times in 2014

Ø The Governance Committee’s duties and responsibilities, which are described in its charter, include the following:

¡ Recommend Board size and membership criteria and identify, evaluate, and recommend Director candidates.

¡ Oversee and make recommendations regarding the composition of the Board and its committees.

¡ Review and make recommendations regarding total compensation for non-employee Directors.

¡ Periodically review and recommend updates to the Corporate Governance Guidelines and Board committee charters.

¡ Coordinate the performance evaluations of the Board and its committees.

¡ Review stock ownership of non-employee Directors annually to ensure compliance with the Company’s Director stock ownership guidelines.

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

(1) Ms. Hudson was appointed as a member of the Governance Committee effective December 1, 2014.

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 describing the candidate’s qualifications, relevant biographical information, and signed consent to serve. These materials should be submitted in writing to the Company’s Corporate Secretary and received by that office by December 12, 2015 for consideration by the Governance Committee as a nominee for election at the Annual Meeting of Stockholders to be held in 2016. Any

stockholder recommendation is reviewed in the same manner as candidates identified by the Governance Committee or recommended to the Governance Committee.

While the Company’s Corporate Governance Guidelines do not prescribe diversity standards, such Guidelines mandate that the Board as a whole should be diverse. At least annually, the Governance Committee evaluates the expertise and needs of the Board to determine the proper membership and size. As part of this evaluation, the Governance Committee considers aspects of diversity, such as diversity of age, race, gender, education, industry, business background, and civic service, in the selection of candidates to serve on the Board. In addition, the Governance Committee also seeks to identify candidates with the capacity to bring relevant experience, relationships, and perspectives regarding the service territories of the Company’s traditional operating subsidiaries, which are primarily in the

  SOUTHERN COMPANY  19

Southeastern United States. Accordingly, the Company uniquely benefits from the experience of Directors who have previously served on the boards of the Company’s subsidiary companies. These operating company boards provide an opportunity for Director candidates to cultivate significant relevant experience with the Company’s business.

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, number of other board memberships, genuine interest in the Company and a recognition that, as a member of the Board, one is accountable to the

stockholders of the Company, not to any particular interest group. The Board as a whole should also have collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and the Company’s industry and service territories.

The Governance Committee recommends candidates to the Board for consideration as nominees. Final selection of the nominees is within the sole discretion of the Board.

Messrs. Larry D. Thompson and John D. Johns were recommended by the Governance Committee for election to the Board and were elected as a Director effective December 1, 2014 and February 9, 2015, respectively. Messrs. Thompson and Johns were identified jointly by members of the Board and management.

Nuclear/Operations Committee

Steven R. Specker Chair

Ø Current members are Dr. Specker (Chair), Ms. Hagen, Ms. Hudson,⁽¹⁾ Dr. Klein, and Mr. Wood

Ø Met five times in 2014

Ø The Nuclear/Operations Committee’s duties and responsibilities, which are described in its charter, include the following:

¡ Oversee information, activities, and events relative to significant operations of the Southern Company system including nuclear and other power generation facilities, transmission and distribution, fuel, and information technology initiatives.

¡ Oversee the Southern Company system’s management of significant construction projects.

¡ Provide input to the Compensation Committee on the Southern Company system’s key operational goals and metrics.

The Board has determined that each member of the Nuclear/Operations Committee is independent.

(1) Ms. Hudson was appointed a member of the Nuclear/Operations Committee effective December 1, 2014.

Business Security Subcommittee

In 2014, the Board established a Business Security Subcommittee of the Nuclear/Operations Committee, comprised of Dr. Klein (Chair) and Ms. Hudson. The Business Security Subcommittee’s responsibilities include

oversight of management’s efforts to establish and continuously improve enterprise-wide security policies, programs, standards, and controls and oversight of management’s efforts to monitor significant security events and operational and compliance activities.

20  SOUTHERN COMPANY

Board Risk Oversight

The Board and its committees have both general and specific risk oversight responsibilities. The Board has broad responsibility to provide oversight of significant risks to the Company primarily through direct engagement with Company management and through delegation of ongoing risk oversight responsibilities to the committees. The charters of the committees as approved by the Board and the committees’ checklists of agenda items define the areas of risk for which each committee is responsible for providing ongoing oversight.

Each committee annually provides ongoing oversight for each of the Company’s most significant risks designated to it as described in its charter or otherwise assigned by the Board, reports to the Board on their oversight activities, and elevates review of risk issues to the Board as appropriate.

For each committee, the Chief Executive Officer of the Company has designated a member of executive management as the primary responsible officer for providing information and updates related to the significant risks. These officers ensure that all significant risks identified on the Company’s risk profile are reviewed with the Board and/or the appropriate committee(s) at least annually.

In addition to oversight of its designated risks, the Audit Committee is also responsible for reviewing the adequacy of the risk oversight process and for reviewing documentation that appropriate risk management and oversight are occurring. In order to fulfill this duty, a report is made to the Audit Committee at least annually.

This report documents which significant risk reviews have occurred and the committee(s) reviewing such risks. In addition, an overview is provided at least annually of the risk assessment and profile process conducted by Company management. At least annually, the Board and the Audit Committee review the Company’s risk profile to ensure that oversight of each risk is properly designated to an appropriate committee or the full Board. Additionally, the Audit Committee receives regular updates from Internal Auditing, as needed, and quarterly updates as part of the disclosure controls process.

The Company believes that its leadership structure supports the risk oversight function of the Board. While the Company has a combined role of Chairman and Chief Executive Officer, an independent Director chairs each committee responsible for providing ongoing oversight of certain areas of risk. Also, there is open communication between the Company’s management and the Directors and all Directors are actively involved in the risk oversight function.

Director Attendance

The Board of Directors met seven times in 2014. Average Director attendance at all applicable Board and committee meetings was 98%. No nominee attended less than 75% of applicable meetings.

All Director nominees are expected to attend the Annual Meeting of Stockholders. All the members of the Board of Directors serving on May 28, 2014, the date of the 2014 Annual Meeting of Stockholders, attended the meeting.

  SOUTHERN COMPANY  21

STOCK OWNERSHIP TABLE

Stock Ownership of Directors, Nominees, and Executive Officers

The following table shows the number of shares of Common Stock beneficially owned by Directors, nominees, and executive officers as of February 28, 2015. 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 Common Stock outstanding.

			Shares Beneficially Owned Include:
Directors, Nominees, and Executive Officers	Shares Beneficially Owned (1)		Deferred Common Stock Units (2)		Shares Individuals Have Rights to Acquire within 60 Days (3)		Shares Held by Family Member (4)
Juanita Powell Baranco		70,407		69,748		—		—
Art P. Beattie		523,200		—		507,587		51
Jon A. Boscia		80,918		21,918		—		—
W. Paul Bowers		1,169,695		—		1,108,858		—
Henry A. Clark III		15,587		15,587		—		—
Thomas A. Fanning		1,461,568		—		1,415,361		—
David J. Grain		20,793		10,002		—		—
Kimberly S. Greene		299,603		—		299,603		—
Veronica M. Hagen		37,138		37,138		—		—
Warren A. Hood, Jr.		47,524		46,863		—		—
Linda P. Hudson		2,696		2,696		—		—
Donald M. James		98,581		98,581		—		—
John D. Johns (5)		22,365		21,915		—		450
Dale E. Klein		12,690		12,690		—		—
Stephen E. Kuczynski		629,919		—		619,320		—
William G. Smith, Jr.		64,331		57,535		—		862
Steven R. Specker		11,937		11,937		—		—
Larry D. Thompson (6)		13,347		1,120		—		—
E. Jenner Wood III		24,204		19,204		—		—
Directors, Nominees, and Executive Officers as a Group (25 people) (7)		6,513,643		426,935		5,774,784		1,363

(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 Common Stock units held under the Director Deferred Compensation Plan that are payable in Common Stock or cash upon departure from the Board. Shares indicated are included in the Shares Beneficially Owned column.

(3) Indicates shares of Common Stock that certain executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column.

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

(5) Mr. Johns was elected to the Board effective February 9, 2015.

(6) Mr. Thompson was elected to the Board effective December 1, 2014.

(7) This item includes all executive officers serving as of February 28, 2015.

22  SOUTHERN COMPANY

Stock Ownership of Certain Other Beneficial Owners

According to a Schedule 13G/A filed with the SEC on February 9, 2015 by Blackrock, Inc., a schedule 13G filed with the SEC on February 12, 2015 by State Street Corporation, and a Schedule 13G/A filed with the SEC on February 11, 2015 by The Vanguard Group (collectively, the Ownership Reports), the following reported beneficial ownership of more than 5% of the outstanding shares of Common Stock:

Title of Class	Name and Address	Shares Beneficially Owned (1)		Percentage of Class Owned (2)
Common Stock	Blackrock, Inc. 55 East 52nd Street New York, NY 10022		52,684,667		5.79
Common Stock	State Street Corporation One Lincoln Street Boston, MA 02111		46,254,789		5.08
Common Stock	The Vanguard Group 100 Vanguard Blvd. Malvern, PA 19355		51,373,414		5.65

(1) According to the Ownership Reports, Blackrock Inc. and State Street Corporation each held all of its shares as a parent holding company or control person in accordance with Rule 13(d)-1(b)(1)(ii)(G) and The Vanguard Group held all of its shares as an investment advisor in accordance with Rule 13(d)-1(b)(1)(ii)(E). According to the Ownership Reports, Blackrock Inc. has sole voting power with respect to 44,684,178 of its shares and sole dispositive power with respect to all 52,684,667 of its shares; State Street Corporation has shared voting and dispositive power with respect to all 46,254,789 of its shares; and The Vanguard Group has sole voting power with respect to 1,603,512 of its shares, sole dispositive power with respect to 49,912,177 of its shares, and shared dispositive power with respect to 1,461,237 of its shares.

(2) Calculated based on 909,877,898 shares outstanding as of January 31, 2015.

  SOUTHERN COMPANY  23

EXECUTIVE COMPENSATION

ITEM NO. 4 — ADVISORY VOTE ON NAMED EXECUTIVE OFFICERS’ COMPENSATION

(the Say-on-Pay vote)

At the 2014 Annual Meeting of Stockholders, the Company provided stockholders with the opportunity to cast an advisory vote regarding the compensation of the named executive officers as disclosed in the 2014 Proxy Statement for the 2014 Annual Meeting of Stockholders. At the meeting, stockholders strongly approved the proposal, with more than 94% of the votes cast voting in favor of the proposal. At the 2011 Annual Meeting, stockholders were asked how frequently the Company should hold a say-on-pay vote — whether every one, two, or three years. Consistent with the recommendation of the Board of Directors, stockholders indicated their preference to hold a say-on-pay vote annually. In light of the Board of Directors’ recommendation and the strong support of the Company’s stockholders, the Board of Directors determined to hold a say-on-pay vote annually.

As described in the Compensation Discussion and Analysis (CD&A) in this Proxy Statement, the Compensation Committee has structured the Company’s executive compensation program based on the belief that executive compensation should:

¡ Be competitive with the Company’s industry peers;

¡ Motivate and reward achievement of the Company’s goals;

¡ Be aligned with the interests of the Company’s stockholders and its subsidiaries’ customers; and

¡ Not encourage excessive risk-taking.

The Company believes these objectives are accomplished through a compensation program that provides the appropriate mix of fixed and short- and long-term performance-based

compensation that rewards achievement of the Company’s financial success, business unit financial and operational success, and total shareholder return. The Company’s financial and operational achievement in 2014 resulted in performance-based awards that were aligned with performance.

All decisions concerning the compensation of the Company’s named executive officers are made by the Compensation Committee, an independent Board committee, with the advice and counsel of an independent executive compensation consultant, Pay Governance.

The Company encourages stockholders to read the Executive Compensation section of this Proxy Statement which includes the CD&A, the Summary Compensation Table, and other related compensation tables, including the information accompanying these tables.

Although it is non-binding on the Board of Directors, the Compensation Committee will review and consider the vote results when making future decisions about the Company’s executive compensation program.

The affirmative vote of a majority of the votes cast is required for approval of the following resolution:

“RESOLVED, that the Company’s stockholders approve, on an advisory basis, the compensation of the Company’s named executive officers, as disclosed in the Proxy Statement for the 2015 Annual Meeting of Stockholders pursuant to the compensation disclosure rules of the Securities and Exchange Commission, including the Compensation Discussion and Analysis, the 2014 Summary Compensation Table, and the other related tables and accompanying narrative set forth in the Proxy Statement.”

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

24  SOUTHERN COMPANY

INDEX TO EXECUTIVE COMPENSATION

	Page
Compensation Discussion and Analysis		26
Establishing Executive Compensation		29
Overview of Executive Compensation Components		30
Establishing Market-Based Compensation Levels		31
Description of Key Compensation Components		33
Performance-Based Compensation Program Changes for 2015		45
Executive Stock Ownership Requirements		46
Impact of Accounting and Tax Treatments on Compensation		47
Policy on Recovery of Awards		47
Policy Regarding Hedging the Economic Risk of Stock Ownership		47
Realizable Performance-Based Compensation Analysis		48
Compensation and Management Succession Committee Report		49

	Page
Summary Compensation Table		50
Grants of Plan-Based Awards in 2014		53
Outstanding Equity Awards at 2014 Fiscal Year-End		55
Option Exercises and Stock Vested in 2014		57
Pension Benefits at 2014 Fiscal Year-End		58
Nonqualified Deferred Compensation as of 2014 Fiscal Year-End		61
Potential Payments upon Termination or Change-in-Control		63
Compensation Risk Assessment		69
Compensation Committee Interlocks and Insider Participation		69
Equity Compensation Plan Information		70

  SOUTHERN COMPANY  25

COMPENSATION DISCUSSION AND ANALYSIS (CD&A)

This section describes the compensation program for the Company’s Chief Executive Officer and Chief Financial Officer in 2014, as well as the compensation program for each of the Company’s other three most highly compensated executive officers serving at the end of the year. Also described is the compensation of Alabama Power’s former President and Chief Executive Officer, Charles D. McCrary, who retired effective May 1, 2014. Collectively, these officers are referred to as the named executive officers.

Thomas A. Fanning	Chairman of the Board, President, and Chief Executive Officer
Art P. Beattie	Executive Vice President and Chief Financial Officer
W. Paul Bowers	Executive Vice President of the Company and Chairman, President, and Chief Executive Officer of Georgia Power
Kimberly S. Greene (1)	Executive Vice President and Chief Operating Officer of the Company
Stephen E. Kuczynski	President and Chief Executive Officer of Southern Nuclear Operating Company (Southern Nuclear)
Charles D. McCrary	Former Executive Vice President of the Company and former Chairman, President, and Chief Executive Officer of Alabama Power

(1) Prior to becoming Executive Vice President and Chief Operating Officer of the Company in March 2014, Ms. Greene served as Executive Vice President of the Company and President and Chief Executive Officer of Southern Company Services, Inc. (SCS).

26  SOUTHERN COMPANY

Executive Summary

Performance and Pay

Performance-based pay represents a substantial portion of the total direct compensation paid or granted to the named executive officers for 2014. Performance-based pay includes both short-term compensation payable in cash on an annual basis (Performance Pay Program) and long-term, equity-based compensation (performance shares and stock options). Both short-term and long-term pay ultimately depend on the financial and operational performance of the Company and its business units.

(1) Salary is the actual amount paid in 2014, Short-Term Performance Pay is the actual amount earned in 2014 based on performance, and Long-Term Performance Pay is the value on the grant date of stock options and performance shares granted in 2014. See the Summary Compensation Table for the amounts of all elements of reportable compensation described in this CD&A. Information is provided for named executive officers serving at the end of 2014.

Short-term performance pay is based on achievement of financial and operational goals that include Company earnings per share (EPS) and business unit financial and operational goals. Company EPS and business unit financial and operational achievement results for 2014, as adjusted and further described in this CD&A, are shown below:

	EPS			Alabama Power Net Income			Georgia Power Net Income			Gulf Power Net Income			Mississippi Power Net Income			Southern Power Net Income			Equity- Weighted Average Net Income
Financial Achievement Results		176	%		176	%		167	%		100	%		124	%		193	%		163	%

	Customer Satisfaction			Reliability			Availability			Nuclear Plant Operations			Safety			Plant Vogtle Units 3 and 4 and Kemper IGCC			Culture			Aggregate Corporate Performance
Corporate Operational Achievement Results		200	%		195	%		190	%		150	%		167	%		Plant Vogtle: 175 Kemper IGCC: 75	% %		150	%		172	%

These performance levels resulted in a composite corporate performance score of 170% of target under the short-term Performance Pay Program.

  SOUTHERN COMPANY  27

Long-term performance pay includes stock options and performances shares, which are granted annually but do not vest until a later date. Stock options vest over a three-year period, while performance shares vest based on Company total shareholder return relative to peers at the end of a three-year performance period. For stock options granted in 2014, the year-end stock price exceeded the grant price by 19%. Performance shares vested on December 31, 2014 for the 2012 through 2014 performance period at 14% of target value, reflecting the Company’s lower total shareholder return relative to the performance share peer groups.

Compensation and Benefit Beliefs and Practices

The Company’s compensation and benefit program is based on the following beliefs:

¡ Employees’ commitment and performance have a significant impact on achieving business results;

¡ Compensation and benefits offered must attract, retain, and engage employees and must be financially sustainable;

¡ Compensation should be consistent with performance: higher pay for higher performance and lower pay for lower performance; and

¡ Both business drivers and culture should influence the compensation and benefit program.

Based on these beliefs, the Compensation Committee believes that the Company’s executive compensation program should:

¡ Be competitive with the Company’s industry peers;

¡ Motivate and reward achievement of the Company’s goals;

¡ Be aligned with the interests of the Company’s stockholders and its subsidiaries’ customers; and

¡ Not encourage excessive risk-taking.

Executive compensation is targeted at the market median of industry peers, but actual compensation is primarily determined by achievement of the Company’s business goals. The Company believes that focusing on the customer drives achievement of financial objectives and delivery of a premium, risk-adjusted total shareholder return for the Company’s stockholders. Therefore, short-term performance pay is based on achievement of the Company’s operational and financial performance goals, with one-third determined by operational performance, such as safety, reliability, and customer satisfaction; one-third determined by business unit financial performance; and one-third determined by EPS performance. Long-term performance pay is tied to stockholder value, with 40% of the target value awarded in stock options, which reward stock price appreciation, and 60% awarded in performance shares, which reward total shareholder return performance relative to that of industry peers and stock price appreciation.

28  SOUTHERN COMPANY

Key Compensation Practices

¡    Annual pay risk assessment required by the Compensation Committee charter.

¡    Retention by the Compensation Committee of an independent compensation consultant, Pay Governance, that provides no other services to the Company.

¡    Inclusion of a claw-back provision that permits the Compensation Committee to recoup performance pay from any employee if determined to have been based on erroneous results, and requires recoupment from an executive officer in the event of a material financial restatement due to fraud or misconduct of the executive officer.

¡    No excise tax gross-up on change-in-control severance arrangements.

¡    Provision of limited ongoing perquisites with no income tax gross-ups, except on certain relocation-related benefits

¡    “No-hedging” provision in the Company’s insider trading policy that is applicable to all employees.

¡    Strong stock ownership requirements that are being met by all named executive officers.

ESTABLISHING EXECUTIVE COMPENSATION

The Compensation Committee establishes the executive compensation program. In doing so, the Compensation Committee uses information from others, principally Pay Governance. The Compensation Committee also relies on information from the Company’s Human Resources staff and, for individual executive officer performance, from the Company’s Chief Executive Officer. The role and information provided by each of these sources is described throughout this CD&A.

Consideration of Advisory Vote on Executive Compensation

The Compensation Committee considered the stockholder vote on the Company’s executive compensation at the 2014 Annual Meeting of Stockholders. In light of the significant support of the stockholders (94% of votes cast voting in favor of the proposal) and the actual payout levels of the performance-based compensation program, the Compensation Committee continues to believe that the Company’s executive compensation program is competitive, aligned with the Company’s financial and operational performance, and in the best interests of the Company, its stockholders, and its subsidiaries’ customers.

Executive Compensation Focus

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

¡ Company EPS and business unit financial and operational performance, based on actual results compared to target performance levels established early in the year, determine the actual payouts under the short-term (annual) performance-based compensation program (Performance Pay Program).

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

¡ Total shareholder return compared to those of industry peers leads to higher or lower payouts under the Performance Share Program (performance shares).

In support of this performance-based pay philosophy, the Company has no general employment contracts or guaranteed severance with the named executive officers, except upon a change in control.

The pay-for-performance principles apply not only to the named executive officers but to

  SOUTHERN COMPANY  29

thousands of employees. The Performance Pay Program covers almost all of the more than 26,000 employees of the Southern Company system. Stock options and performance shares were granted to approximately 3,800 employees

of the Southern Company system. These programs engage employees, which ultimately is good not only for them, but also for the Company and its stockholders.

OVERVIEW OF EXECUTIVE COMPENSATION COMPONENTS

The primary components of the 2014 executive compensation program are shown below:

The Company’s executive compensation program consists of a combination of short-term and long-term components. Short-term compensation includes base salary and the Performance Pay Program. Long-term performance-based compensation includes stock options, performance shares, and, in some cases, restricted stock units. The performance-based compensation components are linked to the Company’s financial and operational

performance, Common Stock performance, and total shareholder return. The executive compensation program is approved by the Compensation Committee, which consists entirely of independent Directors. The Compensation Committee believes that the executive compensation program is a balanced program that provides market-based compensation and motivates and rewards performance.

30  SOUTHERN COMPANY

ESTABLISHING MARKET-BASED COMPENSATION LEVELS

Pay Governance develops and presents to the Compensation Committee competitive market-based compensation levels for each of the named executive officers. The market-based compensation levels are developed from a size-appropriate energy services executive compensation survey database. The survey participants, listed below, are utilities with revenues greater than $6 billion. The Compensation Committee reviews the data and uses it in establishing market-based compensation levels for the named executive officers.

American Electric Power Company, Inc.	GDF SUEZ North America
Bg US Services, Inc.	Kinder Morgan, Inc.
Calpine Corporation	National Grid USA
CenterPoint Energy, Inc.	NextEra Energy, Inc.
CMS Energy Corporation	NRG Energy, Inc.
Consolidated Edison, Inc.	PG&E Corporation
Dominion Resources, Inc.	PPL Corporation
DTE Energy Company	Public Service Enterprise Group Inc.
Duke Energy Corporation	Sempra Energy
Edison International	Tennessee Valley Authority
Energy Transfer Partners, L.P.	The AES Corporation
Entergy Corporation	The Williams Companies, Inc.
Eversource Energy	UGI Corporation
Exelon Corporation	Xcel Energy Inc.
First Energy Corp.

The Company is one of the largest utility holding companies in the United States based on revenues and market capitalization, and its largest business units are some of the largest in the industry as well. For that reason, Pay Governance uses size-appropriate survey market data in order to fit it to the scope of the Company’s business.

Market data for the Chief Executive Officer position and other positions in terms of scope of responsibilities that most closely resemble the positions held by the named executive officers is reviewed with the Compensation Committee. When appropriate, the market data is size-adjusted, up or down, to accurately reflect comparable scopes of responsibilities. Based on that data, a total target compensation opportunity is established for each named executive officer. Total target compensation opportunity is the sum of base salary, annual performance-based compensation at a target performance level, and long-term performance-

based compensation (stock options and performance shares) at a target value. Actual compensation paid may be more or less than the total target compensation opportunity based on actual performance above or below target performance levels. As a result, the compensation program is designed to result in payouts that are market-appropriate given the Company’s performance for the year or period.

A specified weight was not targeted for base salary or annual or long-term performance-based compensation as a percentage of total target compensation opportunities, nor did amounts realized or realizable from prior compensation serve to increase or decrease 2014 compensation amounts. Total target compensation opportunities for senior management as a group, including the named executive officers, are managed to be at the median of the market for companies of similar size in the electric utility industry. Therefore, some executives may be paid above and others

  SOUTHERN COMPANY  31

below market. This practice allows for 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. Because of the use of market data from a large number of industry peer companies for positions that are not identical in terms of scope of responsibility from company to company, differences are not considered to be material and the compensation program is believed to be market-appropriate, as long as senior management as a group is within an appropriate range. Generally, compensation is considered to be within an appropriate range if it is not more or less than 15% of the applicable market data.

The Compensation Committee, working with Pay Governance, annually reviews the mix of key

compensation components to assess the effectiveness of the executive compensation program in providing the appropriate levels of fixed and at-risk performance-based pay that is aligned with the Company’s short- and long-term business strategies.

Based on this assessment, the Compensation Committee established the total target compensation opportunity in early 2014 for each named executive officer. The Compensation Committee believes that the compensation for the Company’s officers, particularly the Chief Executive Officer and the other named executive officers, should be strongly tied to performance. As the chart below depicts, the fixed pay (base salary) for Mr. Fanning is only 14% of his total target compensation opportunity and ranges from 25% to 28% for the other named executive officers. Variable (at-risk) performance-based compensation is 86% for Mr. Fanning and 72% to 75% for the other named executive officers.

The salary levels shown above were not effective until March 2014. Therefore, the salary amounts reported in the Summary Compensation Table are different than the amounts shown above because that table reports actual amounts paid in 2014. The total target compensation opportunity amount shown for Mr. McCrary represents the full amount had he been

employed the entire year by Alabama Power. However, the actual amounts Mr. McCrary received for salary and annual performance-based compensation were prorated based on the amount of time he was employed at Alabama Power in 2014. Additionally, the ultimate number of performance shares earned by Mr. McCrary will be prorated based on the

32  SOUTHERN COMPANY

time he was employed during the performance period. See the Summary Compensation Table and Grants of Plan-Based Awards in 2014 for more information on the actual compensation amounts Mr. McCrary received.

For purposes of comparing the value of the compensation program to the market data, stock options are valued at $2.20 per option and performance shares at $37.54 per unit. These values represent risk-adjusted present values on the date of grant and are consistent with the methodologies used to develop the market data. The mix of stock options and performance shares granted was 40% and 60%, respectively, of the long-term value shown above.

In 2013, Pay Governance analyzed the level of actual payouts for 2012 performance under the annual Performance Pay Program made to the named executive officers relative to performance versus peer companies to provide a check on the goal-setting process, including goal levels and associated performance-based pay opportunities. The findings from the analysis were used in establishing performance goals and the associated range of payouts for goal achievement for 2014. That analysis was updated in 2014 by Pay Governance for 2013 performance, and those findings were used in establishing goals for 2015.

DESCRIPTION OF KEY COMPENSATION COMPONENTS

2014 Base Salary

Base salary amounts for each of the named executive officers were recommended in 2014 for the Compensation Committee’s approval by Mr. Fanning, except for his own salary. Those recommendations took into account the market data provided by Pay Governance, as well as the need to retain an experienced team, internal equity, time in position, and individual performance. Individual performance includes the degree of competence and initiative exhibited and the individual’s relative contribution to the achievement of financial and operational goals in prior years. Based on these factors, most of the named executive officers received base salary increases in 2014, ranging

from 1% to 4%, consistent with increases for most other employees.

2014 Performance-Based Compensation

This section describes performance-based compensation for 2014.

Achieving Operational and Financial Performance Goals — The Guiding Principle for Performance-Based Compensation

The Southern Company system’s number one priority is to continue to provide customers outstanding reliability and superior service at reasonable prices while achieving a level of financial performance that benefits the Company’s stockholders in the short and long term. Operational excellence and business unit and Company financial performance are integral to the achievement of business results that benefit customers and stockholders.

Therefore, in 2014, the Company strove for and rewarded:

¡ Continuing industry-leading reliability and customer satisfaction, while maintaining reasonable retail prices;

¡ Meeting energy demand with the best economic and environmental choices;

¡ Dividend growth;

¡ Long-term, risk-adjusted total shareholder return;

¡ Achieving net income goals to support the Southern Company financial plan and dividend growth; and

¡ Financial integrity — an attractive risk-adjusted return and sound financial policy.

The performance-based compensation program is designed to encourage achievement of these goals.

Mr. Fanning, with the assistance of the Company’s Human Resources staff, recommended to the Compensation Committee the program design and award amounts for senior management, including the named executive officers (other than Mr. Fanning).

  SOUTHERN COMPANY  33

2014 Annual Performance-Based Pay Program

Annual Performance Pay Program Highlights

¡    Rewards achievement of annual performance goals:

 ¡   EPS

 ¡   Business unit net income

  ¡   Business unit operational performance

¡    Goals are weighted one-third each

¡   Performance results range from 0% to 200% of target, based on level of goal achievement

¡    Performance summary (as adjusted and described below): exceeded target performance

 ¡   EPS: 176% of target

  ¡   Corporate equity-weighted average net income result: 163% of target

  ¡   Corporate weighted-average operational results: 172% of target

Overview of Program Design

Almost all employees of the Southern Company system, including the named executive officers, are participants.

The performance goals are set at the beginning of each year by the Compensation Committee and include financial and operational goals. In setting the goals for pay purposes, the Compensation Committee relies on information on financial and operational goals from the Finance Committee and the Nuclear/Operations Committee, respectively. For more information on these committees’ responsibilities, see the committee descriptions in this Proxy Statement.

¡ Company Financial Goal: EPS

EPS is defined as the Company’s net income from ongoing business activities divided by average shares outstanding during the year. The EPS performance measure is applicable to all participants in the Performance Pay Program.

¡ Business Unit Financial Goal: Net Income

For the traditional operating companies (Alabama Power, Georgia Power, Gulf Power Company (Gulf Power), and Mississippi Power) and Southern Power, the business unit financial goal is net income. There is no separate net income goal set for the Company as a whole or for Southern Nuclear. Overall corporate performance is determined by the equity-weighted average of the business unit net income goal payouts. Payment for Southern Nuclear performance is based on the net income

achievement of Alabama Power (50%) and Georgia Power (50%).

¡ Business Unit Operational Goals: Varies by business unit

For most business units at the Company, including the traditional operating companies, operational goals are safety, customer satisfaction, plant availability, transmission and distribution system reliability, major projects (Georgia Power and Mississippi Power), and culture. Southern Nuclear operational goals focus on safety, plant operations, major projects, and culture. Southern Power operational goals include safety, plant availability, and culture. Each of these operational goals is explained in more detail under Goal Details below. The level of achievement for each operational goal is determined according to the respective performance schedule, and the total operational goal performance is determined by the weighted average result.

The Compensation Committee may make adjustments, both positive and negative, to goal achievement for purposes of determining payouts. For the financial goals, such adjustments typically include the impact of items considered non-recurring or outside of normal operations or not anticipated in the business plan when the financial goals were established and of sufficient magnitude to warrant recognition. As reported in the Company’s 2014 Proxy Statement, the Compensation Committee did not follow its usual practice, and the charges taken in 2013 related to

34  SOUTHERN COMPANY

Mississippi Power’s construction of the integrated coal gasification combined cycle facility in Kemper County (Kemper IGCC) were not excluded from goal achievement results. Because the charges were not excluded, the payout levels for all employees, including the named executive officers, were reduced significantly in 2013. In 2014, the Company recorded pre-tax charges to earnings of $868 million ($536 million after-tax, or $0.59 per share) (2014 Kemper IGCC Charges) due to estimated probable losses relating to the Kemper IGCC. Additionally, Southern Company adjusted its 2014 net income by $17 million after-tax (or $0.02 per share) relating to the reversal of previously recognized revenues recorded in 2014 and 2013 and the recognition of carrying costs associated with the 2015 Mississippi Supreme Court decision that reversed the Mississippi Public Service Commission’s March 2013 rate order associated with the Kemper IGCC (together with the 2014 Kemper IGCC Charges, 2014 Kemper IGCC Charges and Adjustments). The Compensation Committee reviewed the impact of the 2014 Kemper IGCC Charges and Adjustments on goal achievement and payout levels for all Southern Company system employees, including the named executive officers. The Compensation Committee determined that, given the action taken last year and the high levels of achievement of other performance goals in 2014, it was not appropriate to reduce payouts earned in 2014 under the broad-based program applicable to all participating employees. Therefore, the Compensation Committee made an adjustment to exclude the impact of the 2014 Kemper IGCC Charges and Adjustments ($0.61 per share) from earnings as it relates to the EPS goal payout for most Southern Company system employees.

As described in greater detail below in Calculating Payouts, Ms. Greene and Messrs. Fanning and Beattie are paid based on the equity-weighted average of the business unit net income results, which includes the net income goal achievement for Mississippi Power. Due to the 2014 Kemper IGCC Charges and Adjustments described above, Mississippi Power recorded a net loss of $328.7 million, resulting in below-threshold performance and would have resulted in no payout associated

with the Mississippi Power portion of the net income goal for thousands of employees across the Southern Company system, including Ms. Greene and Messrs. Fanning and Beattie, as well as no payout at all for the business unit financial goal for all Mississippi Power employees. With the adjustment made by the Compensation Committee, Mississippi Power’s net income for purposes of calculating goal achievement was $224 million. The adjusted net income resulted in a higher payout for the net income goal for all Mississippi Power employees as well as a higher payout associated with the overall equity-weighted average net income results for several thousand other employees across the Southern Company system whose payouts are determined by the equity-weighted average of the business unit net income results, including Ms. Greene and Messrs. Fanning and Beattie.

As described above, the adjustment to earnings as it relates to the EPS goal payout applied to employees across the entire Southern Company system, and the adjustment to Mississippi Power’s net income goal achievement affected thousands of employees across the Southern Company system, including certain named executive officers. However, because the strategic goals related to the Kemper IGCC were not fully executed in 2014, the Compensation Committee determined that the final payout for certain executive officers most accountable for high-level strategic decisions concerning the Kemper IGCC, including some of the named executive officers, should be reduced from the amount they would have otherwise received. The Compensation Committee reduced payouts for Ms. Greene (25%) and Messrs. Fanning (30%), Beattie (10%), and Bowers (10%). See Calculating Payouts in this CD&A for a full description of how payouts were calculated for all of the named executive officers.

Under the terms of the program, no payout can be made if events occur that impact the Company’s financial ability to fund the Common Stock dividend. The 2014 Kemper IGCC Charges and Adjustments described above did not have that effect.

  SOUTHERN COMPANY  35

Goal Details and 2014 Performance Results

Financial Performance Goals	Description	Why It Is Important
EPS	The Company’s net income from ongoing business activities divided by average shares outstanding during the year.	Supports commitment to provide stockholders solid, risk-adjusted returns.
Business Unit Net Income	For the traditional operating companies and Southern Power, the business unit financial performance goal is net income after dividends on preferred and preference stock.	Supports delivery of stockholder value and contributes to the Company’s sound financial policies and stable credit ratings.

The range of EPS and net income goals for 2014 is shown below. Overall corporate performance is determined by the equity-weighted average of the business unit net income goal payouts.

	EPS ($) (1)		Alabama Power ($, in millions)		Georgia Power ($, in millions)		Gulf Power ($, in millions)		Mississippi Power ($, in millions) (2)		Southern Power ($, in millions)		Corporate Equity- Weighted Average (2) (%)
Maximum		2.90		774.0		1,258.0		153.0		240.7		175.0		200
Target		2.76		717.0		1,160.0		140.2		218.6		135.0		100
Threshold		2.62		661.0		1,063.0		127.4		196.4		95.0		***
Results		2.80		760.6		1,225.0		140.2		224.0		172.3		163

(1) The EPS result shown in the table excludes the 2014 Kemper IGCC Charges and Adjustments ($0.61 per share) as described above. Therefore, payouts were determined using an EPS performance result that differed from the results reported in the Company’s financial statements in the 2014 Annual Report attached as Appendix D to this Proxy Statement (Financial Statements). EPS, as determined in accordance with generally accepted accounting principles in the United States (GAAP) and as reported in the Financial Statements, was $2.19 per share.

(2) The corporate net income result is the equity-weighted average of the business unit net income results, including the net income result for Mississippi Power. Mississippi Power’s net income result for this purpose was impacted by the adjustment for the 2014 Kemper IGCC Charges and Adjustments ($553 million on an after-tax basis). Therefore, payouts were determined using a net income performance result that differed from the results reported in the Financial Statements. Mississippi Power recorded a net loss, as determined in accordance with GAAP, of $328.7 million.

36  SOUTHERN COMPANY

Operational Goals	Description	Why It Is Important
Customer Satisfaction	Customer satisfaction surveys evaluate 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.	Customer satisfaction is key to operations. Performance of all operational goals affects customer satisfaction.
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 recent historical performance.	Reliably delivering power to customers is essential to operations.
Availability	Peak season equivalent forced outage rate is an indicator of availability and efficient generation fleet operations during the months when generation needs are greatest. Availability is measured as a percentage of the hours of forced outages out of the total generation hours.	Availability of sufficient power during peak season fulfills the obligation to serve and provide customers with the least cost generating resources.
Nuclear Plant Operations	Nuclear plant performance is evaluated by measuring nuclear safety as rated by independent industry evaluators, as well as by a quantitative score comprised of various plant performance indicators. Plant reliability and operational availability are measured as a percentage of time the nuclear plant is operating. The reliability and availability metrics take generation reductions associated with planned outages into consideration.	Safe and efficient operation of the nuclear fleet is important for delivering clean energy at a reasonable price.
Major Projects – Plant Vogtle Units 3 and 4 and Kemper IGCC	The Southern Company system is committed to the safe, compliant, and high-quality construction and licensing of two new nuclear generating units under construction at Georgia Power’s Plant Vogtle (Plant Vogtle Units 3 and 4) and the Kemper IGCC, as well as excellence in transition to operations and prudent decision-making related to these two major projects. An executive review committee is in place for each project to assess progress. A combination of subjective and objective measures is considered in assessing the degree of achievement. Final assessments for each project are approved by either the Company’s Chief Executive Officer or the Company’s Chief Operating Officer and confirmed by the Nuclear/Operations Committee.	Strategic projects enable the Southern Company system to expand capacity to provide clean, affordable energy to customers across the region.
Safety	The Company’s Target Zero program is focused on continuous improvement in having a safe work environment. The performance is measured by the applicable company’s ranking, as compared to peer utilities in the Southeastern Electric Exchange.	Essential for the protection of employees, customers, and communities.
Culture	The culture goal seeks to improve the Company’s inclusive workplace. This goal includes measures for work environment (employee satisfaction survey), representation of minorities and females in leadership roles (subjectively assessed), and supplier diversity.	Supports workforce development efforts and helps to assure diversity of suppliers.

  SOUTHERN COMPANY  37

The ranges of performance levels established for the primary operational goals are detailed below, along with actual corporate results for 2014 performance.

Level of Performance	Customer Satisfaction	Reliability	Availability	Nuclear Plant Operations	Safety	Plant Vogtle Units 3 and 4 and Kemper IGCC	Culture
Maximum	Top quartile for all customer segments and overall	Significantly exceed targets	Industry best	Significantly exceed targets	Greater than 90th percentile or 5-year Company best	Significantly exceed targets	Significant improvement
Target	Top quartile overall	Meet targets	Top quartile	Meet targets	60th percentile	Meet targets	Improvement
Threshold	2nd quartile overall	Significantly below targets	2nd quartile	Significantly below targets	40th percentile	Significantly below targets	Significantly below expectations
Corporate Achievement	200%	195%	190%	150%	167%	Plant Vogtle: 175% Kemper IGCC: 75%	150%

The Compensation Committee approves specific objective performance schedules to calculate performance between the threshold, target, and maximum levels for each of the operational goals. If goal achievement is below threshold, there is no payout associated with the applicable goal.

Actual 2014 operational goal achievement is shown in the following tables.

Corporate (Ms. Greene and Messrs. Fanning and Beattie)

Company Corporate/Aggregate Goal	Achievement Percentage
Customer Satisfaction	200
Reliability	195
Availability	190
Safety	167
Culture	150
Major Projects – Plant Vogtle Units 3 and 4 Assessment	175
Major Projects – Kemper IGCC Assessment	75
Total Operational Goal Performance Factor	172

Alabama Power (Mr. McCrary)

Goal	Achievement Percentage
Customer Satisfaction	200
Reliability	177
Availability	200
Safety	165
Culture	130
Total Operational Goal Performance Factor	176

38  SOUTHERN COMPANY

Georgia Power (Mr. Bowers)

Goal	Achievement Percentage
Customer Satisfaction	200
Reliability	172
Availability	200
Safety	80
Major Projects – Plant Vogtle Units 3 and 4 Assessment	175
Culture	137
Total Operational Goal Performance Factor	162

Southern Nuclear (Mr. Kuczynski)

Goal	Achievement Percentage
Nuclear Safety	0
Plant Operations	150
Major Projects – Plant Vogtle Units 3 and 4 Assessment	175
Culture	131
Total Operational Goal Performance Factor	123

Calculating Payouts

Each named executive officer had a target Performance Pay Program opportunity, based on his or her position, set by the Compensation Committee at the beginning of 2014. Targets are set as a percentage of base salary.

All of the named executive officers are paid based on EPS performance. The business unit goals that determine payout levels vary based on the named executive officer’s leadership role. For Ms. Greene and Messrs. Fanning and Beattie, payout is based on the equity-weighted average net income payout results for the traditional operating companies and Southern Power and the system-wide operational goal results. For Messrs. Bowers and McCrary, payout is based on achievement of the net income and operational goals of Georgia Power and Alabama Power,

respectively. Mr. McCrary’s payout is prorated based on the amount of time he was employed at Alabama Power during 2014. Mr. Kuczynski’s payout is based on the achievement percentages of the net income goals of Alabama Power (50%) and Georgia Power (50%) and the Southern Nuclear operational goal results.

A total performance factor is determined by adding the EPS and applicable business unit financial and operational goal performance results and dividing by three. The total performance factor is multiplied by the target Performance Pay Program opportunity to determine the payout for each named executive officer. The table below shows the calculation of the total performance factor for each of the named executive officers, based on results shown above.

	Southern Company   EPS Result (%) 1/3 weight (1)	Business Unit   Financial Goal   Result (%) 1/3 weight (1)	Business Unit Operational   Goal Result (%)   1/3 weight	Total   Performance   Factor (%)
T. A. Fanning	176	163	172	170
A. P. Beattie	176	163	172	170
W. P. Bowers	176	166	162	168
K. S. Greene	176	163	172	170
S. E. Kuczynski	176	171	123	157
C. D. McCrary	176	176	176	176

(1) Excluding impact of the 2014 Kemper IGCC Charges and Adjustments.

  SOUTHERN COMPANY  39

The table below shows the pay opportunity at target-level performance and the actual payout based on the actual performance shown above.

	Target Annual Performance Pay Program Opportunity (%)	Target Annual Performance Pay Program Opportunity ($)	Total Performance Factor (%) (1)	Actual Annual Performance Pay Program Payout ($) (2)
T. A. Fanning	120	1,440,000	170	1,713,600
A. P. Beattie	75	505,123	170	772,839
W. P. Bowers	75	590,503	168	892,841
K. S. Greene	70	455,000	170	580,125
S. E. Kuczynski	70	467,875	157	734,564
C. D. McCrary (3)	75	602,435	176	333,990

(1) Shown as modified and described above.

(2) As described above, the Compensation Committee reduced the final payouts for Ms. Greene (25%) and Messrs. Fanning (30%), Beattie (10%), and Bowers (10%) after the adjustments to performance results in connection with the 2014 Kemper IGCC Charges and Adjustments.

(3) Mr. McCrary retired from Alabama Power effective May 1, 2014; therefore, his Performance Pay Program payout was prorated based on the amount of time he was employed in 2014. The target amount shown is his full target opportunity as if he had been employed for the entire year. The actual amount shown is the prorated amount Mr. McCrary received.

Long-Term Performance-Based Compensation

2014 Long-Term Pay Program Highlights    

¡   StockOptions:

¡   Rewardlong-term Common Stock price appreciation

¡  Represent40% of long-term target value

¡   Vestover three years

¡   Ten-yearterm

¡   PerformanceShares:

¡   Rewardtotal shareholder return relative to industry peers and stock price appreciation

¡  Represent60% of long-term target value

¡   Three-yearperformance period

¡  Performanceresults can range from 0% to 200% of target

¡  Paidin Common Stock at end of performance period

¡   RestrictedStock Units

¡   Usedto promote retention of key employees or to attract key employees by replacing award  values forfeited upon leaving a former employer

¡   Continuedemployment until vesting date(s) is required

¡  Paidin Common Stock upon vesting

¡  PerformanceSummary:

¡    Stockoptions: for options granted in 2014, year-end stock price exceeded option exercise price  by nearly 19%

¡   Performanceshares: paid out at 14% of target

¡  Restrictedstock units: one new grant in 2014 to Mr. Kuczynski

40  SOUTHERN COMPANY

Long-term performance-based awards are intended to promote long-term success and increase stockholder value by directly tying a substantial portion of the named executive officers’ total compensation to the interests of stockholders. Long-term performance-based awards also benefit the Southern Company system’s customers by providing competitive compensation that allows the Southern Company system to attract, retain, and engage employees who provide focus on serving customers and delivering safe and reliable electric service.

Stock options represent 40% of the long-term performance target value, and performance

shares represent the remaining 60%. The Compensation Committee elected this mix because it concluded that doing so represented an appropriate balance between incentives. Stock options only generate value if the price of the stock appreciates after the grant date, and performance shares reward employees based on Southern Company’s total shareholder return relative to industry peers, as well as Common Stock price. The Compensation Committee also awards restricted stock units occasionally, typically as retention awards or to attract key employees by replacing the value of awards that are forfeited upon leaving a former employer.

The following table shows the grant date fair value of the long-term performance-based awards granted in 2014, except restricted stock units.

	Value of Options ($)		Value of Performance Shares ($)		Total Long-Term Value ($)
T. A. Fanning		2,255,999		3,383,968		5,639,967
A. P. Beattie		619,617		929,415		1,549,032
W. P. Bowers		724,350		1,086,520		1,810,870
K. S. Greene		467,999		701,998		1,169,997
S. E. Kuczynski		454,507		681,726		1,136,233
C. D. McCrary		722,920		1,084,380		1,807,300

Stock Options

Stock options granted 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. For the grants made in 2014, unvested options are forfeited if the named executive officer retires from the Southern Company system and accepts a position with a peer company within two years of retirement. The grants made to Mr. McCrary in 2014 vested upon his retirement; however, he will forfeit those options that vested upon retirement if he accepts a position with a peer company within two years of his retirement. The value of each stock option was derived using the Black-Scholes stock option pricing model. The assumptions used in calculating that amount are

discussed in Note 8 to the Financial Statements. For 2014, the Black-Scholes value on the grant date was $2.20 per stock option, and the exercise price is $41.28.

Performance Shares

2014-2016 Grant

Performance shares are denominated in units, meaning no actual shares are issued on the grant date. A grant date fair value per unit was determined. For the grant made in 2014, the value per unit was $37.54. See the Summary Compensation Table and the information accompanying it for more information on the grant date fair value. The total target value for performance share units is divided by the value per unit to determine the number of

  SOUTHERN COMPANY  41

performance share units granted to each participant, including the named executive officers. Each performance share unit represents one share of Common Stock.

At the end of the three-year performance period (January 1, 2014 through December 31, 2016), the number of units will be adjusted up or down (0% to 200%) based on the Company’s total shareholder return relative to that of its peers in a custom peer group. While in previous years the Company’s total shareholder return was measured relative to two peer groups (a custom peer group and the Philadelphia Utility Index), the Compensation Committee decided to streamline the performance share peer group for the 2014 grant by eliminating the Philadelphia Utility Index and establishing one custom peer group. The companies in the custom peer group

are those that are believed to be most similar to the Company in both business model and investors, creating a peer group that is even more aligned with the Company’s strategy. For performance shares granted in previous years using the dual peer group structure, the final result will be measured using both peer groups as approved by the Compensation Committee at the time of the grant. The custom peer group varies from the Market Data peer group discussed previously due to the timing and criteria of the peer selection process; however, there is significant overlap. The number of performance share units earned will be paid in Common Stock at the end of the three-year performance period. No dividends or dividend equivalents will be paid or earned on the performance share units.

The companies in the custom peer group on the grant date are listed in the following table.

Alliant Energy Corporation	Integrys Energy Group
Ameren Corporation	Pepco Holdings, Inc.
American Electric Power Company, Inc.	PG&E Corporation
CMS Energy Corporation	Pinnacle West Capital Corporation
Consolidated Edison, Inc.	PPL Corporation
DTE Energy Company	SCANA Corporation
Duke Energy Corporation	Wisconsin Energy Corporation
Edison International	Xcel Energy Inc.
Eversource Energy

The scale below will determine the number of units paid in Common Stock following the last year of the performance period, based on the 2014 through 2016 performance period. Payout for performance between points will be interpolated on a straight-line basis.

Performance vs. Peer Group	Payout (% of Each Performance Share Unit Paid)
90th percentile or higher (Maximum)		200
50th percentile (Target)		100
10th percentile (Threshold)		0

Performance shares are not earned until the end of the three-year performance period. A participant who terminates, other than due to retirement or death, forfeits all unearned performance shares. Participants who retire or

die during the performance period only earn a prorated number of units, based on the number of months they were employed during the performance period.

42  SOUTHERN COMPANY

2012-2014 Payouts

Performance share grants were made in 2012 with a three-year performance period that ended on December 31, 2014. Based on the Company’s total shareholder return achievement relative to that of the Philadelphia Utility Index (28% payout) and the custom peer group (0% payout) as shown in the chart below, the payout percentage was 14% of target, which is the average of the two peer groups.

The following table shows the target and actual awards of performance shares for the named executive officers. Actual payouts were significantly below the target grant value due to lower relative total shareholder return.

	Target Performance Shares (#)		Target Value of Performance Shares ($)		Performance Shares Earned (#)		Value of Performance Shares Earned ($)
T. A. Fanning		72,338		3,037,473		10,127		497,337
A. P. Beattie		18,417		773,330		2,578		126,606
W. P. Bowers		23,906		1,003,813		3,347		164,371
K. S. Greene (1)		0		0		0		0
S. E. Kuczynski		14,717		617,967		2,060		101,167
C. D. McCrary (2)		25,121		1,054,831		2,735		134,316

(1) Ms. Greene was not employed by the Southern Company system when the Compensation Committee granted performance shares in 2012.

(2) The number of performance shares earned by Mr. McCrary is prorated based on the time he was employed by Alabama Power during the performance period.

  SOUTHERN COMPANY  43

Restricted Stock Units

In limited situations, restricted stock units are granted to address specific needs, including retention. These awards serve two primary purposes. They further align the recipient’s interests with those of the Company’s stockholders, and they provide strong retention value. For information on treatment upon termination or change in control, see Potential Payments Upon Termination or Change-in-Control.

In October 2014, the Compensation Committee granted Mr. Kuczynski restricted stock units valued at $1,000,016 on the grant date that will vest in October 2017 if he remains employed with the Southern Company system through the vesting date. The Compensation Committee believes that, given Mr. Kuczynski’s expertise and the competitiveness of the nuclear labor market, there is a retention risk and, therefore, providing a retention award was in the best interest of the Company. The Compensation Committee sought advice from Pay Governance in determining market practice and the appropriate value of the award.

Restricted stock units were granted to Ms. Greene in 2013 and will vest incrementally each year starting April 1, 2015 and ending April 1, 2018 if she remains employed with the Southern Company system.

Restricted stock units were granted to Mr. McCrary in 2012 with a vesting date of December 31, 2014 in order to retain Mr. McCrary until his successor was named and expiration of an appropriate transition period. Mr. McCrary’s successor was announced in February 2014, and Mr. McCrary retired effective May 1, 2014. The Compensation Committee modified the vesting date to April 30, 2014.

See the Summary Compensation Table, the Grants of Plan-Based Awards table, the Outstanding Equity Awards at 2014 Fiscal Year End table, and accompanying information for more information on restricted stock unit awards.

Timing of Performance-Based Compensation

As discussed above, the 2014 annual Performance Pay Program goals and the total shareholder return goals applicable to performance shares were established early in the year by the Compensation Committee. Annual stock option grants also were made by the Compensation Committee. The establishment of performance-based compensation goals and the granting of equity awards were not timed with the release of material, non-public information. This procedure is 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 2014 was the closing price of the Common Stock on the grant date or the last trading day before the grant date, if the grant date was not a trading day.

Retirement and Severance Benefits

Certain post-employment compensation is provided to employees, including the named executive officers, consistent with the Company’s goal of providing market-based compensation and benefits.

Retirement Benefits

Generally, all full-time employees of the Southern Company system participate in the funded Pension Plan after completing one year of service. Normal retirement benefits become payable when participants attain age 65 and complete five years of participation. The Company also provides unfunded benefits that count salary and annual Performance Pay Program payouts that are ineligible to be counted under the Pension Plan. See the Pension Benefits table and accompanying information for more pension-related benefits information.

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

44  SOUTHERN COMPANY

performance-based non-equity compensation 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 accompanying information for more information about the Deferred Compensation Plan.

Change-in-Control Protections

Change-in-control protections, including severance pay and, in some situations, vesting or payment of long-term performance-based awards, are provided upon a change in control of the Company coupled with an involuntary termination not for cause or a voluntary termination for “Good Reason.” This means there is a “double trigger” before severance benefits are paid; i.e., there must be both a change in control and a termination of employment. Severance payment amounts are two times salary plus target Performance Pay Program opportunity for the named executive officers,

except for Mr. Fanning whose severance payment amount is three times salary plus Performance Pay Program target opportunity. No excise tax gross-up would be provided. Change-in-control protections allow executive officers to focus on potential transactions that are in the best interest of shareholders. More information about severance arrangements is included under Potential Payments upon Termination or Change-in-Control.

Perquisites

The Company provides limited ongoing perquisites to its executive officers, including the named executive officers, consistent with the Company’s goal of providing market-based compensation and benefits. The perquisites provided in 2014, including amounts, are described in detail in the information accompanying the Summary Compensation Table. No tax assistance is provided on perquisites, except on certain relocation-related benefits.

PERFORMANCE-BASED COMPENSATION PROGRAM CHANGES FOR 2015

In early 2015, the Compensation Committee made several changes to the Company’s performance-based compensation programs, impacting 2015 compensation. These changes affect both the annual Performance Pay Program as well as the long-term performance-based compensation program and are described below.

Annual Performance-Based Pay Program

Beginning in 2015, the annual performance-based pay program will incorporate individual goals for all executive officers of the Company. Currently, the goals are equally weighted between the EPS goal, the applicable business

unit net income goal, and the applicable business unit operational goals. Starting with the 2015 annual Performance Pay Program goals, the Compensation Committee eliminated the business unit net income goal for the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), added an individual goal component, and changed the weights for the EPS goal and operational goals. All other executive officers will now have four goals: EPS, business unit net income, business unit operational goals, and their individual goals. The table below outlines the new weights for each goal.

	EPS			Net Income			Operational			Individual
CEO and CFO		40	%		0	%		30	%		30	%
All other executive officers		30	%		30	%		30	%		10	%

Long-Term Performance-Based Compensation

Since 2010, the Company’s long-term performance-based compensation program has

included two components: stock options and performance shares. After reviewing current market practices with Pay Governance, the Compensation Committee decided to modify the Company’s long-term performance-based

  SOUTHERN COMPANY  45

compensation program to further align the Company’s compensation program with its peers in the utility industry and create better alignment of pay with long-term Company performance. Beginning with long-term performance-based equity grants made in early 2015, the long-term performance-based program consists exclusively of performance shares. The new structure maintains the three-year performance cycle described earlier in this CD&A for performance shares but expands the performance metrics from one (relative total shareholder return) to three metrics. The new program now includes relative total shareholder return (50%), cumulative EPS from ongoing operations over a three-year period (25%), and equity-weighted return on equity (ROE) (25%). Under the new program, dividends will accrue on performance shares throughout the performance period, and eligible new hires and newly promoted employees will receive interim prorated grants of performance shares instead of stock options.

The continued use of relative total shareholder return as a metric in the long-term performance program maintains consistency with the previous program as well as allows the Company to measure its performance against a custom group of regulated peers. The new EPS goal measures cumulative EPS from ongoing operations over a three-year period and motivates ongoing earnings growth to support the Company’s dividend and achievement of

strategic financial objectives. The new equity-weighted ROE goal measures traditional operating company performance from ongoing operations over a three-year period and is set to encourage top quartile ROE performance. Both the EPS and ROE goals are subject to a gateway goal focused on the Company’s credit ratings. If the Company fails to meet the credit rating requirements established by the Compensation Committee, there will be no payout associated with the EPS and ROE goals.

EXECUTIVE STOCK OWNERSHIP REQUIREMENTS

Officers of the Company and its subsidiaries that are in a position of Vice President or above are subject to stock ownership requirements. All of the named executive officers are covered by the requirements. Ownership requirements 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. Beattie is 60.

The requirements are expressed as a multiple of base salary as shown below.

	Multiple of Salary without Counting Stock Options	Multiple of Salary Counting 1/3 of Vested Options
T. A. Fanning	5 Times	10 Times
A. P. Beattie	1.5 Times	3 Times
W. P. Bowers	3 Times	6 Times
K. S. Greene	3 Times	6 Times
S. E. Kuczynski	3 Times	6 Times

Newly-elected officers have approximately five years from the date of their election to meet the applicable ownership requirement. Newly-promoted officers have approximately five years from the date of their promotion to meet the

increased ownership requirement. All of the named executive officers are meeting their respective ownership requirements. Mr. McCrary retired and is therefore no longer subject to stock ownership requirements.

46  SOUTHERN COMPANY

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 the compensation of the named executive officers, except Messrs. Beattie and McCrary, 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 the performance-based compensation is paid. Because the Company’s 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. The Compensation Committee has the discretion to award compensation that may not be tax deductible.

The Compensation Committee approved a formula in February 2014 that represented a maximum annual performance-based compensation amount payable to the affected named executive officers. For 2014 performance, the Compensation Committee used negative discretion from the approved formula amount to

determine the actual payouts for the affected named executive officers under the annual performance-based compensation program pursuant to the methodologies described above.

POLICY ON RECOVERY OF AWARDS

The Company’s Omnibus Incentive Compensation Plan provides that, if the Company is required to prepare an accounting restatement due to material noncompliance as a result of misconduct, and if an executive officer of the Company knowingly or grossly negligently engaged in or failed to prevent the misconduct or is subject to automatic forfeiture under the Sarbanes-Oxley Act of 2002, the executive officer must repay 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.

POLICY REGARDING HEDGING THE ECONOMIC RISK OF STOCK OWNERSHIP

The Company’s policy is that employees and outside Directors will not trade Company options on the options market and will not engage in short sales.

  SOUTHERN COMPANY  47

REALIZABLE PERFORMANCE-BASED COMPENSATION ANALYSIS

The SEC has promulgated rules regarding how total compensation is calculated in the Summary Compensation Table. These rules include accounting assumptions that affect the value reported for equity grants. However, as the Company’s performance changes over time, the Common Stock price can fluctuate, affecting the value of equity grants made to the named executive officers. The Compensation Committee believes it is important to look at those changes to fully understand the value of the compensation received because the reported value is only realized if the Company meets certain performance criteria. In order to supplement the SEC-required disclosure, the chart below compares the target or grant date value of performance-based compensation granted to Mr. Fanning in 2012, 2013, and 2014 with the value actually received or as measured on December 31, 2014.

The realizable amount shown for short-term performance pay includes the actual amount paid to Mr. Fanning for 2012, 2013, and 2014 under the Performance Pay Program.

The realizable amount shown for stock options includes the intrinsic value of all stock options granted to Mr. Fanning in 2012, 2013, and 2014 calculated using the Common Stock closing price on December 31, 2014. This amount is subject to change based on changes in the Common Stock price.

The realizable amount shown for performance shares includes the value Mr. Fanning received based on the payout of the performance shares granted in 2012 for the 2012 through 2014 performance period as well as the projected amounts based on performance levels relative to peers as of December 31, 2014 for the 2013 and 2014 grants. This amount is subject to change based on the Company’s performance relative to its peers at the end of the applicable three-year performance period. See Performance Shares in this CD&A for a description of the Company’s performance share peer group.

48  SOUTHERN COMPANY

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, 2014 and in this Proxy Statement. The Board of Directors approved that recommendation.

Members of the Compensation Committee:

Henry A. Clark III, Chair

David J. Grain

Veronica M. Hagen

William G. Smith, Jr.

Steven R. Specker

  SOUTHERN COMPANY  49

SUMMARY COMPENSATION TABLE

The Summary Compensation Table shows the amount and type of compensation received or earned in 2012, 2013, and 2014 by the named executive officers, except as noted below.

Name and Principal Position (a)	Year (b)		Salary ($) (c)		Bonus ($) (d)		Stock Awards ($) (e)		Option Awards ($) (f)		Non-Equity Incentive Plan Compensation ($) (g)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (h)		All Other Compensation ($) (i)		Total ($) (j)
Thomas A. Fanning Chairman, President, and Chief Executive Officer		2014		1,192,067		—		3,383,968		2,255,999		1,713,600		2,899,537		70,822		11,515,993
		2013		1,152,389		—		3,128,625		2,085,747		1,199,307		805,738		66,485		8,438,291
		2012		1,114,846		—		3,037,473		2,025,000		2,078,158		4,712,413		67,458		13,035,348
Art P. Beattie Executive Vice President and Chief Financial Officer		2014		668,516		—		929,415		619,617		772,839		1,396,842		37,293		4,424,522
		2013		644,039		—		796,514		531,025		437,126		402,101		122,037		2,932,842
		2012		615,378		—		773,330		515,558		737,382		2,747,374		34,352		5,423,374
W. Paul Bowers Chairman, President, and Chief Executive Officer, Georgia Power		2014		782,928		45		1,086,520		724,350		892,841		1,504,316		46,986		5,037,986
		2013		760,482		—		1,031,940		687,964		498,775		—		44,375		3,023,536
		2012		739,587		42		1,003,813		669,227		1,013,366		2,024,578		50,830		5,501,443
Kimberly S. Greene Executive Vice President and Chief Operating Officer		2014		650,000		—		701,998		467,999		580,125		326,334		605,315		3,331,771
		2013		475,000		—		2,000,005		1,039,997		310,811		212,666		656,035		4,694,514
Stephen E. Kuczynski President and Chief Executive Officer, Southern Nuclear		2014		667,120		—		1,681,742		454,507		734,564		217,633		39,117		3,794,683
		2013		658,378		—		635,283		423,534		426,183		126,714		42,692		2,312,784
		2012		640,289		—		617,967		411,997		619,288		77,727		101,886		2,469,154
Charles D. McCrary Former Chairman, President, and Chief Executive Officer, Alabama Power		2014		389,266		—		2,896,902		722,920		333,990		923,064		96,937		5,363,079
		2013		799,124		—		1,084,347		722,922		650,630		414,103		45,396		3,716,522
		2012		777,167		—		3,054,840		703,232		1,028,204		2,437,448		44,722		8,045,613

Column (a)

Ms. Greene was not an executive officer of the Company prior to 2013.

Column (d)

This amount shown for Mr. Bowers reflects the value of a non-cash safety award for Mr. Bowers. All employees of Georgia Power with a perfect individual safety record in 2014 received the award.

Column (e)

This column does not reflect the value of stock awards that were actually earned or received in

2014. Rather, as required by applicable rules of the SEC, this column reports the aggregate grant date fair value of performance shares granted in 2014. The value reported is based on the probable outcome of the performance conditions as of the grant date, using a Monte Carlo simulation model. No amounts will be earned until the end of the three-year performance period on December 31, 2016. The value then can be earned based on performance ranging from 0 to 200%, as established by the Compensation Committee. The aggregate grant date fair value of the performance shares granted in 2014 to Ms. Greene and Messrs. Fanning, Beattie, Bowers, and Kuczynski, assuming that the highest level of performance

50  SOUTHERN COMPANY

is achieved, is $1,403,996, $6,767,936, $1,858,830, $2,173,040, and $1,363,453, respectively (200% of the amount shown in the table). Because Mr. McCrary retired from Alabama Power effective May 1, 2014, the maximum amount he could earn is $241,007, which is prorated based on the number of months he was employed during the performance period. The amount reflected in column (e) for Mr. McCrary also includes the incremental fair value related to the modification of the vesting date of the restricted stock units granted to Mr. McCrary in 2012 and discussed in the CD&A. See Note 8 to the Financial Statements for a discussion of the assumptions used in calculating these amounts.

Column (f)

This column reports the aggregate grant date fair value of stock options granted in the applicable year. 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 payouts under the annual Performance Pay Program. The amount reported for the Performance Pay Program is for the one-year performance period that ended on December 31, 2014. The Performance Pay Program is described in detail in the CD&A.

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) as of December 31, 2012, 2013, and 2014. Because Mr. McCrary retired in 2014, the amount reported for him in 2014 reflects the actual benefits expected to be paid after the measurement date. The Pension Benefits as of each measurement date are based on the named executive officer’s age, pay, and service accruals and the plan provisions applicable as of the measurement date. The actuarial present values as of each measurement date reflect the

assumptions the Company selected for cost purposes as of that measurement date; however, the named executive officers were assumed to remain employed at the Company or any Company subsidiary until their benefits commence at the pension plans’ stated normal retirement date, generally age 65. As a result, the amounts in column (h) related to Pension Benefits represent the combined impact of several factors: growth in the named executive officer’s Pension Benefits over the measurement year; impact on the total present values of one year shorter discounting period due to the named executive officer being one year closer to normal retirement; impact on the total present values attributable to changes in assumptions from measurement date to measurement date; and impact on the total present values attributable to plan changes between measurement dates. In general, pension values increased for all named executive officers due to a decrease in discount rates and updated mortality rates.

For more information about the Pension Benefits and the assumptions used to calculate the actuarial present value of accumulated benefits as of December 31, 2014, see the information following the Pension Benefits table. The key differences between assumptions used for the actuarial present values of accumulated benefits calculations as of December 31, 2013 and December 31, 2014 are:

¡ Discount rate for the Pension Plan was decreased to 4.20% as of December 31, 2014 from 5.05% as of December 31, 2013;

¡ Discount rate for the supplemental pension plans was decreased to 3.75% as of December 31, 2014 from 4.50% as of December 31, 2013; and

¡ Mortality rates for all plans were updated due to the release of new mortality tables.

This column also reports above-market earnings on deferred compensation under the Deferred Compensation Plan (DCP). However, there were no above-market earnings on deferred compensation in the years reported.

  SOUTHERN COMPANY  51

Column (i)

This column reports the following items: perquisites; tax reimbursements on certain relocation-related benefits and retirement-related financial planning assistance; employer contributions in 2014 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 2014 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 2014 are itemized below.

	Perquisites ($)		Tax Reimbursements ($)		ESP ($)		SBP ($)		Total ($)
T. A. Fanning		10,023		—		13,260		47,539		70,822
A. P. Beattie		5,022		—		11,437		20,834		37,293
W. P. Bowers		7,464		—		12,853		26,669		46,986
K. S. Greene		400,708		171,457		13,260		19,890		605,315
S. E. Kuczynski		9,241		—		9,113		20,763		39,117
C. D. McCrary		84,345		—		11,199		1,393		96,937

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 a financial planner on behalf of the officers, up to a maximum amount of $8,700 per year, after the initial year that the benefit is provided. In the initial year, the allowed amount is $15,000. The Company also provides a five-year allowance of $6,000 for estate planning and tax return preparation fees.

Relocation Benefits are provided to cover the costs associated with geographic relocation. In 2014, Ms. Greene received relocation-related benefits in the amount of $363,155 in connection with her 2014 relocation from Atlanta, Georgia to Birmingham, Alabama. This amount was for the shipment of household goods, incidental expenses related to her move, and home sale and home repurchase assistance. Also, as provided in the Company’s relocation policy, tax assistance is provided on the taxable relocation benefits. If Ms. Greene terminates within two years of her relocation, these amounts must be repaid.

Personal Use of Corporate Aircraft. The Southern Company system has aircraft that are used to facilitate business travel. All flights on these aircraft must have a business purpose, except limited personal use that is associated with

business travel is permitted. The amount reported for such personal use is the incremental cost of providing the benefit, primarily fuel costs. 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. The perquisite amount shown above for Mr. Bowers includes $1,664 for approved personal use of corporate aircraft. In connection with Ms. Greene’s relocation, the Compensation Committee approved personal use of the corporate aircraft for weekly round-trip flights between Atlanta and Birmingham for the first twelve months following her relocation to Birmingham. The perquisite amount shown above for Ms. Greene includes $32,379 for this approved personal use of corporate aircraft.

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.

52  SOUTHERN COMPANY

GRANTS OF PLAN-BASED AWARDS IN 2014

This table provides information on stock option grants made and goals established for future payouts under the performance-based compensation programs during 2014 by the Compensation Committee.

Name (a)	Grant Date (b)		Estimated Future Payouts Under Non- Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards						All Other Stock Awards: Number of Shares of Stock or Units (#) (i)		All Other Option Awards: Number of Securities Underlying Options (#) (j)		Exercise or Base Price of Option Awards ($/Sh) (k)		Grant Date Fair Value of Stock and Option Awards ($) (l)
			Threshold ($) (c)		Target ($) (d)		Maximum ($) (e)		Threshold (#) (h)		Target (#) (g)		Maximum (#) (h)
T. A. Fanning				14,400		1,440,000		2,880,000
		2/10/2014								901		90,143		180,286								3,383,968
		2/10/2014																1,025,454		41.28		2,255,999
A. P. Beattie				5,051		505,123		1,010,247
		2/10/2014								247		24,758		49,516								929,415
		2/10/2014																281,644		41.28		619,617
W. P. Bowers				5,905		590,503		1,181,007
		2/10/2014								289		28,943		57,886								1,086,520
		2/10/2014																329,250		41.28		724,350
K. S. Greene				4,550		455,000		910,000
		2/10/2014								187		18,700		37,400								701,998
		2/10/2014																212,727		41.28		467,999
S. E. Kuczynski				4,679		467,875		935,750
		2/10/2014								181		18,160		36,320								681,726
		2/10/2014																206,594		41.28		454,507
		10/20/2014														21,377						1,000,016
C. D. McCrary				1,898		189,767		379,534
		2/10/2014								288		28,886		57,772								1,084,380
		2/10/2014																328,600		41.28		722,920
		2/10/2014														43,908						1,812,522

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

These columns reflect the annual Performance Pay Program opportunity granted to the named executive officers in 2014 as described in the CD&A. The information shown as “Threshold,” “Target,” and “Maximum” reflects the range of potential payouts established by the Compensation Committee. The actual amounts earned are disclosed in the Summary Compensation Table. The amounts shown for Mr. McCrary are prorated based on the amount of time he was employed at Alabama Power in 2014.

Columns (f), (g), and (h)

These columns reflect the performance shares granted to the named executive officers in 2014, as described in the CD&A. The information shown as “Threshold,” “Target,” and “Maximum” reflects the range of potential payouts established by the Compensation Committee. Earned performance shares will be paid out in Common Stock following the end of the 2014 through 2016 performance period, based on the extent to which the performance goals are achieved. Any shares not earned are forfeited.

The number of shares shown for Mr. McCrary reflects the full grant he received in February

  SOUTHERN COMPANY  53

2014. However, since Mr. McCrary retired in May 2014, the ultimate number of performance shares he will receive will be prorated based on the number of months he was employed by Alabama Power during the performance period.

Column (i)

This column reflects the number of restricted stock units granted to Mr. Kuczynski on the grant date as described in the CD&A. This column also reflects the restricted stock units granted to Mr. McCrary in 2012 and modified by the Compensation Committee in February 2014, as described in the CD&A.

Columns (j) and (k)

Column (j) reflects the number of stock options granted to the named executive officers in 2014, as described in the CD&A, and column (k) reflects the exercise price of the stock options, which was the closing price on the grant date.

Column (l)

This column reflects the aggregate grant date fair value of the performance shares, stock options, and restricted stock units granted in 2014. This column also reflects the incremental fair value of the restricted stock units granted to Mr. McCrary in 2012 and modified in February 2014. For performance shares, the value is based on the probable outcome of the performance conditions as of the grant date using a Monte Carlo simulation model. For stock options, the value is derived using the Black-Scholes stock option pricing model. For the restricted stock units granted to Mr. Kuczynski, the value is based on the closing price of Common Stock on the grant date. According to SEC rules, the incremental fair value of the restricted stock units granted to Mr. McCrary in 2012 and modified in February 2014 is reported using the value on the modification date. The assumptions used in calculating these amounts are discussed in Note 8 to the Financial Statements.

54  SOUTHERN COMPANY

OUTSTANDING EQUITY AWARDS AT 2014 FISCAL YEAR-END

This table provides information pertaining to all outstanding stock options and stock awards (performance shares and restricted stock units) held by or granted to the named executive officers as of December 31, 2014.

	Option Awards								Stock Awards
Name (a)	Number of Securities Underlying Unexercised Options Exercisable (#) (b)		Number of Securities Underlying Unexercised Options Unexercisable (#) (c)		Option Exercise Price ($) (d)		Option Expiration Date (e)		Number of Shares or Units of Stock That Have Not Vested (#) (f)		Market Value of Shares or Units of Stock That Have Not Vested ($) (g)		Equity Incentive Plan Awards: Number of Unearned Shares, Units, or Other Rights That Have Not Vested (#) (h)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units, or Other Rights That Have Not Vested ($) (i)
T. A. Fanning		398,230		199,115		44.42		2/13/2022
		238,099		476,198		44.06		2/11/2023
		—		1,025,454		41.28		2/10/2024
														77,250		3,793,748
														90,143		4,426,923
A. P. Beattie		140,384		—		37.97		2/14/2021
		101,388		50,694		44.42		2/13/2022
		60,620		121,238		44.06		2/11/2023
		—		281,644		41.28		2/10/2024
														19,667		965,846
														24,758		1,215,865
W. P. Bowers		70,680		—		36.42		2/19/2017
		85,151		—		35.78		2/18/2018
		90,942		—		31.39		2/16/2019
		233,477		—		31.17		2/15/2020
		164,377		—		37.97		2/14/2021
		131,608		65,804		44.42		2/13/2022
		78,535		157,069		44.06		2/11/2023
		—		329,250		41.28		2/10/2024
														25,480		1,251,323
														28,943		1,421,391
K. S. Greene		109,705		219,408		46.74		4/1/2023
		—		212,727		41.28		2/10/2024
														18,700		918,357
										46,425		2,279,932
S. E. Kuczynski		332,225		—		40.14		7/11/2021
		81,022		40,511		44.42		2/13/2022
		48,349		96,697		44.06		2/11/2023
		—		206,594		41.28		2/10/2024
														15,686		770,339
														18,160		891,838
										30,931		1,519,021
C. D. McCrary		207,443		—		44.42		2/13/2022
		247,576		—		44.06		2/11/2023
		328,600		—		41.28		2/10/2024
														26,774		1,314,871
														28,886		1,418,591

  SOUTHERN COMPANY  55

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

Stock options vest one-third per year on the anniversary of the grant date. Options granted from 2007 through 2011 with expiration dates from 2017 through 2021 were fully vested as of December 31, 2014. The options granted in 2012, 2013, and 2014 become fully vested as shown below.

Year Option Granted	Expiration Date		Date Fully Vested
2012		February 13, 2022		February 13, 2015
2013		February 11, 2023		February 11, 2016
2014		February 10, 2024		February 10, 2017

Options also fully vest upon death, total disability, or retirement and expire three years following death or total disability or five years following retirement, or on the original expiration date if earlier. Please see Potential Payments upon Termination or Change-in-Control for more information about the treatment of stock options under different termination and change-in-control events.

Columns (f) and (g)

These columns reflect the number of restricted stock units, including the deemed reinvestment of dividends, held as of December 31, 2014. The value in column (g) is based on the Common Stock closing price on December 31, 2014 ($49.11). The restricted stock units for Ms. Greene vest incrementally each year starting April 1, 2015 and ending April 1, 2018 if she remains employed with the Southern Company system. The restricted stock units for Mr. Kuczynski vest on December 31, 2017 if he remains employed with the Southern Company system on the vesting date. See further discussion of restricted stock units in the CD&A. See also Potential Payments upon Termination or Change-in-Control for more information about the treatment of restricted stock units under different termination and change-in-control events.

Columns (h) and (i)

In accordance with SEC rules, column (h) reflects the target number of performance shares that can be earned at the end of each three-year performance period (December 31, 2015 and 2016) that were granted in 2013 and 2014, respectively. The performance shares granted for the 2012 through 2014 performance period vested on December 31, 2014 and are shown in the Option Exercises and Stock Vested in 2014 table below.

The value in column (i) is derived by multiplying the number of shares in column (h) by the Common Stock closing price on December 31, 2014 ($49.11). The ultimate number of shares earned, if any, will be based on the actual performance results at the end of each respective performance period. The ultimate number of shares earned by Mr. McCrary will be prorated based on the number of months he was employed by Alabama Power during the performance periods. See further discussion of performance shares in the CD&A. See also Potential Payments upon Termination or Change-in-Control for more information about the treatment of performance shares under different termination and change-in-control events.

56  SOUTHERN COMPANY

OPTION EXERCISES AND STOCK VESTED IN 2014

	Option Awards				Stock Awards
Name (a)	Number of Shares Acquired on Exercise (#) (b)		Value Realized on Exercise ($) (c)		Number of Shares Acquired on Vesting (#) (d)		Value Realized on Vesting ($) (e)
T. A. Fanning		1,049,185		10,336,745		10,127		497,337
A. P. Beattie		57,983		547,091		2,578		126,606
W. P. Bowers		128,093		1,628,963		3,347		164,371
K. S. Greene		—		—		—		—
S. E. Kuczynski		—		—		2,060		101,167
C. D. McCrary		452,498		4,169,084		50,311		2,314,724

Columns (b) and (c)

Column (b) reflects the number of shares acquired upon the exercise of stock options during 2014, and column (c) reflects the value realized. The value realized is the difference in the market price over the exercise price on the exercise date.

Columns (d) and (e)

Column (d) includes the performance shares awarded for the 2012 through 2014 performance period that vested on December 31, 2014. The value reflected in column (e) is derived by multiplying the number of shares that vested by the market value of the underlying shares on the vesting date ($49.11).

Because Ms. Greene was not an employee of the Southern Company system when performance shares were awarded in 2012, column (d) does not reflect any vested performance shares for her.

Certain restricted stock units with reinvested dividends vested on April 30, 2014 and are reflected in column (d) for Mr. McCrary. The value of the restricted stock units as shown in column (e) is derived by multiplying the number of restricted stock units and reinvested dividends that vested (47,576) by the market value of the underlying shares on the vesting date ($45.83).

  SOUTHERN COMPANY  57

PENSION BENEFITS AT 2014 FISCAL YEAR-END

Name (a)	Plan Name (b)	Number of Years Credited Service (#) (c)		Present Value of Accumulated Benefit ($) (d)		Payments During Last Fiscal Year ($) (e)
T. A. Fanning	Pension Plan		33.0		1,359,877		—
	Supplemental Benefit Plan (Pension-Related)		33.0		10,947,004		—
	Supplemental Executive Retirement Plan		33.0		4,468,682		—
A. P. Beattie	Pension Plan		37.92		1,737,633		—
	Supplemental Benefit Plan (Pension-Related)		37.92		5,206,128		—
	Supplemental Executive Retirement Plan		37.92		2,011,301		—
W. P. Bowers	Pension Plan		34.67		1,445,025		—
	Supplemental Benefit Plan (Pension-Related)		34.67		5,671,484		—
	Supplemental Executive Retirement Plan		34.67		1,860,971		—
K. S. Greene	Pension Plan		7.17		203,653		—
	Supplemental Benefit Plan (Pension-Related)		7.17		192,443		—
	Supplemental Executive Retirement Plan		7.17		255,522		—
S. E. Kuczynski	Pension Plan		2.58		89,419		—
	Supplemental Benefit Plan (Pension-Related)		2.58		223,065		—
	Supplemental Executive Retirement Plan		2.58		109,590		—
C. D. McCrary	Pension Plan		39.33		1,931,424		77,806
	Supplemental Benefit Plan (Pension-Related)		39.33		8,522,909		920,251
	Supplemental Executive Retirement Plan		39.33		2,688,067		290,241

Pension Plan

The Pension Plan is a tax-qualified, funded plan. It is the Company’s primary retirement plan. Generally, all full-time Southern Company system employees participate in this plan after one year of service. Normal retirement benefits become payable when participants 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 rates of pay considered for this formula are the base salary rates with no adjustments for voluntary deferrals after 2008. A statutory limit restricts the amount considered each year; the limit for 2014 was $260,000.

The 1.25% formula amount equals 1.25% of final average pay times years of participation. For this formula, the final average pay computation is the same as above, but annual performance-based compensation earned each year is added to the base salary rates.

Early retirement benefits become payable once plan participants have, during employment, attained age 50 and completed 10 years of participation. Participants who retire early from active service receive benefits equal to the

58  SOUTHERN COMPANY

amounts computed using the same formulas employed at normal retirement. However, a 0.3% reduction applies for each month (3.6% for each year) prior to normal retirement that participants elect to have their benefit payments commence. For example, 64% of the formula benefits are payable starting at age 55. As of December 31, 2014, all of the named executive officers are retirement-eligible except Ms. Greene and Mr. Kuczynski.

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. As of December 31, 2014, all of the named executive officers are vested in their Pension Plan benefits except Mr. Kuczynski. Ms. Greene received years of credited service for her previous employment with the Southern Company system. Participants who terminate employment after vesting can elect to have their pension benefits commence 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 and is either age 50 or vested in the Pension Plan as of date of death, 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 this extra service crediting, the normal Pension 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. The SBP-P’s vesting and early retirement provisions mirror those of the Pension Plan. Its disability provisions mirror those of the Pension Plan but cease upon a participant’s separation from service.

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 a 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 U.S. 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

  SOUTHERN COMPANY  59

credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a “key man” under Section 409A of the Code, the first installment will be delayed for six months after the date of separation.

If a SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participant’s death occurs prior to age 50, the installments will be paid to a spouse 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 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 performance-based compensation. To derive the SERP benefits, a final average pay is determined reflecting participants’ base rates of pay and their annual performance-based compensation amounts, whether or not deferred, to the extent they exceed 15% of those base rates (ignoring statutory limits). 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, disability, and form of payment 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 retirement-eligible. More information about vesting and payment of SERP benefits following a change in control is included under Potential Payments upon Termination or Change-in-Control.

Pension Benefit Assumptions

The following assumptions were used in the present value calculations for all pension benefits:

¡ Discount rate — 4.20% Pension Plan and 3.75% supplemental plans as of December 31, 2014,

¡ Retirement date — Normal retirement age (65 for all named executive officers),

¡ Mortality after normal retirement — RP-2014 mortality tables with generational projections,

¡ Mortality, withdrawal, disability, and retirement rates prior to normal retirement — None,

¡ Form of payment for Pension Benefits:

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

¡ Female retirees: 75% single life annuity; 15% level income annuity; 5% joint and 50% survivor annuity; and 5% joint and 100% survivor annuity

¡ Spouse ages — Wives two years younger than their husbands,

¡ Annual performance-based compensation earned but unpaid as of the measurement date — 130% of target opportunity percentages times base rate of pay for year amount is earned, and

¡ Installment determination — 3.75 % discount rate for single sum calculation and 4.25% prime rate during installment payment period.

For all of the named executive officers, the number of years of credited service is one year less than the number of years of employment. The number of years of credited service for Ms. Greene reflects her previous employment with the Southern Company system.

Columns (d) and (e)

For Mr. McCrary, who retired effective May 1, 2014, column (d) reflects the actual benefits expected to be paid, and column (e) reflects the actual amount paid under the Pension Plan in 2014, as described above.

60  SOUTHERN COMPANY

NONQUALIFIED DEFERRED COMPENSATION AS OF 2014 FISCAL YEAR-END

Name (a)	Executive Contributions in Last FY ($) (b)		Employer Contributions in Last FY ($) (c)		Aggregate Earnings in Last FY ($) (d)		Aggregate Withdrawals/ Distributions ($) (e)		Aggregate Balance at Last FYE ($) (f)
T. A. Fanning		239,141		47,539		337,542		—		3,360,041
A. P. Beattie		—		20,834		53,350		—		554,209
W. P. Bowers		149,632		26,669		650,324		—		4,510,207
K. S. Greene		—		19,890		4,795		—		35,944
S. E. Kuczynski		—		20,763		11,919		—		71,858
C. D. McCrary		—		1,393		113,931		1,709,936		3,967

The Company provides the DCP, which is designed to permit participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement or other separation from service. Up to 50% of base salary and up to 100% of performance-based non-equity compensation may be deferred at the election of eligible employees. All of the named executive officers are eligible to participate in the DCP.

Participants have two options for the deemed investments of the amounts deferred — the Stock Equivalent Account and the Prime Equivalent Account. Under the terms of the DCP, participants are permitted to transfer between investments at any time.

The amounts deferred in the Stock Equivalent Account are treated as if invested at an equivalent rate of return to that of an actual investment in Common Stock, including the crediting of dividend equivalents as such are paid by Southern Company from time to time. It provides participants with an equivalent opportunity for the capital appreciation (or loss) and income of that of a Company stockholder. During 2014, the rate of return in the Stock Equivalent Account was 25.27%.

Alternatively, participants may elect to have their deferred compensation deemed invested in the Prime Equivalent Account, which is treated as if invested at a prime interest rate compounded monthly, as published in The Wall Street Journal as the base rate on corporate loans posted as of

the last business day of each month by at least 75% of the United States’ largest banks. The interest rate earned on amounts deferred during 2014 in the Prime Equivalent Account was 3.25%.

Column (b)

This column reports the actual amounts of compensation deferred under the DCP by each named executive officer in 2014. The amount of salary deferred by the named executive officers, if any, is included in the Salary column in the Summary Compensation Table. The amounts of performance-based compensation deferred in 2014 were the amounts that were earned as of December 31, 2013 but were not payable until the first quarter of 2014. These amounts are not reflected in the Summary Compensation Table because that table reports performance-based compensation that was earned in 2014 but not payable until early 2015. These deferred amounts may be distributed in a lump sum or in up to 10 annual installments at termination of employment or in a lump sum at a specified date, at the election of the participant.

Column (c)

This column reflects contributions under the SBP. Under the Code, employer-matching contributions are prohibited under the ESP on employee contributions above stated limits in the ESP, and, if applicable, above legal limits set forth in the Code. The SBP is a nonqualified deferred compensation plan under which contributions are made that are prohibited from

  SOUTHERN COMPANY  61

being made in the ESP. The contributions are treated as if invested in Common Stock and are payable in cash upon termination of employment in a lump sum or in up to 20 annual installments, at the election of the participant. The amounts reported in this column also were reported in the All Other Compensation column in the Summary Compensation Table.

Column (d)

This column reports earnings or losses on both compensation the named executive officers elected to defer and on employer contributions under the SBP.

Column (f)

This column includes amounts that were deferred under the DCP and contributions under the SBP in prior years. The following chart shows the amounts previously reported.

	Amounts Deferred under the DCP prior to 2014 and previously reported ($)		Employer Contributions under the SBP prior to 2014 and previously reported ($)		Total ($)
T. A. Fanning		1,936,157		368,900		2,305,057
A. P. Beattie		34,781		61,314		96,095
W. P. Bowers		1,981,253		143,292		2,124,545
K. S. Greene		0		11,220		11,220
S. E. Kuczynski		0		19,905		19,905
C. D. McCrary		489,924		376,220		866,144

62  SOUTHERN COMPANY

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE-IN-CONTROL

This section describes and estimates payments that could be made to the named executive officers serving as of December 31, 2014 under different termination and change-in-control events. The estimated payments would be made under the terms of Southern Company’s compensation and benefit program or the change-in-control severance program. All of the named executive officers are participants in Southern Company’s change-in-control severance program for officers. The amount of potential payments is calculated as if the triggering events occurred as of December 31, 2014 and assumes that the price of Common Stock is the closing market price on December 31, 2014.

Description of Termination and Change-in-Control Events

The following charts list different types of termination and change-in-control events that can affect the treatment of payments under the compensation and benefit programs. No payments are made under the change-in-control severance program 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 of a named executive officer who is not retirement-eligible not for cause.

¡ 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 the subsidiary company level:

¡ Company Change-in-Control I — Consummation of an acquisition by another entity of 20% or more of Common Stock or, following consummation of a merger with another entity, the Company’s stockholders own 65% or less of the entity surviving the merger.

¡ Company Change-in-Control II — Consummation of an acquisition by another entity of 35% or more of Common Stock or, following consummation of a merger with another entity, the Company’s stockholders own less than 50% of the Company surviving the merger.

¡ Company Termination — Consummation of a merger or other event and the Company is not the surviving company or Common Stock is no longer publicly traded.

¡ Subsidiary Company Change-in-Control — Consummation of an acquisition by another entity, other than another subsidiary of the Company, of 50% or more of the stock of any of the Company’s subsidiaries, consummation of a merger with another entity and the Company’s subsidiary is not the surviving company, or the sale of substantially all the assets of any of the Company’s subsidiaries.

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

  SOUTHERN COMPANY  63

voluntary termination within two years of a change in control generally is satisfied when there is a material reduction in salary,

performance-based compensation opportunity or benefits, relocation of over 50 miles, or a diminution in duties and responsibilities.

The following chart describes the treatment of different pay and benefit elements in connection with the Traditional Termination Events as described above.

Program	Retirement/ Retirement- Eligible	Lay Off (Involuntary Termination Not For Cause)	Resignation	Death or Disability	Involuntary Termination (For Cause)
Pension Benefits Plans	Benefits payable as described in the notes following the Pension Benefits table.	Same as Retirement.	Same as Retirement.	Same as Retirement.	Same as Retirement.
Annual Performance Pay Program	Prorated if retire before 12/31.	Same as Retirement.	Forfeit.	Same as Retirement.	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 date or three years.	Forfeit.
Performance Shares	Prorated if retire prior to end of performance period.	Forfeit.	Forfeit.	Same as Retirement.	Forfeit.
Restricted Stock Units	Forfeit.	Vest.	Forfeit.	Vest.	Forfeit.
Financial Planning Perquisite	Continues for one year.	Terminates.	Terminates.	Same as Retirement.	Terminates.
DCP	Payable per prior elections (lump sum or up to 10 annual installments).	Same as Retirement.	Same as Retirement.	Payable to beneficiary or participant per prior elections. Amounts deferred prior to 2005 can be paid as a lump sum per the benefit administration committee’s discretion.	Same as Retirement.
SBP – non-pension related	Payable per prior elections (lump sum or up to 20 annual installments).	Same as Retirement.	Same as Retirement.	Same as the DCP	Same as Retirement.

64  SOUTHERN COMPANY

The following chart describes the treatment of payments under compensation and benefit programs under different change-in-control events, except the Pension Plan. The Pension Plan is not affected by change-in-control events.

Program	Company Change-in-Control I	Company Change-in-Control  II	Company Termination or Subsidiary Company Change-in- Control	Involuntary Change-in- Control-Related Termination or Voluntary Change-in- Control-Related Termination for Good Reason
Nonqualified Pension Benefits	All SERP-related benefits vest if participants vested in tax-qualified pension benefits; otherwise, no impact. SBP - pension-related benefits vest for all participants and single sum value of benefits earned to change-in-control date paid following termination or retirement.	Benefits vest for all participants and single sum value of benefits earned to the change-in-control date paid following termination or retirement.	Same as Company Change-in-Control II.	Based on type of change-in-control event.
Annual Performance Pay Program	If no program termination, paid at greater of target or actual performance. If program terminated within two years of change-in-control, prorated at target performance level.	Same as Company Change-in-Control I.	Prorated at target performance level.	If not otherwise eligible for payment, if the program is still in effect, prorated at target performance level.
Stock Options	Not affected by change-in-control events.	Not affected by change-in-control events.	Vest and convert to surviving company’s securities; if cannot convert, pay spread in cash.	Vest.
Performance Shares	Not affected by change-in-control events.	Not affected by change-in-control events.	Vest and convert to surviving company’s securities; if cannot convert, pay spread in cash.	Vest.
RSUs	Not affected by change-in-control events.	Not affected by change-in-control events.	Vest and convert to surviving company’s securities; if cannot convert, pay spread in cash.	Vest.
DCP	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.
SBP	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.	Not affected by change-in-control events.
Severance Benefits	Not applicable.	Not applicable.	Not applicable.	Two or three times base salary plus target annual performance-based pay.
Healthcare Benefits	Not applicable.	Not applicable.	Not applicable.	Up to five years participation in group healthcare plan plus payment of two or three years’ premium amounts.
Outplacement Services	Not applicable.	Not applicable.	Not applicable.	Six months.

  SOUTHERN COMPANY  65

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, 2014.

Pension Benefits

The amounts that would have become payable to the named executive officers if the Traditional Termination Events occurred as of December 31, 2014 under the Pension Plan, the SBP-P, and the SERP are itemized in the following chart. The amounts shown under the Retirement column are amounts that would have become payable to the named executive officers that were retirement-eligible on December 31, 2014 and are the monthly Pension Plan benefits and the first of 10 annual installments from the SBP-P and the SERP. The amounts shown under the Resignation or Involuntary Termination column are the amounts that would have become payable to the named executive officers who were not retirement-eligible on December 31, 2014 and are the monthly Pension Plan benefits that would become payable as of the earliest possible date under the Pension Plan and the single sum value of benefits earned up to the

termination date under the SBP-P, paid as a single payment rather than in 10 annual installments. Benefits under the SERP would be forfeited. The amounts shown that are payable to a spouse in the event of the death of the named executive officer are the monthly amounts payable to a spouse under the Pension Plan and the first of 10 annual installments from the SBP-P and the SERP. The amounts in this chart are very different from the pension values shown in the Summary Compensation Table and the Pension Benefits table. Those tables show the 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. Of the named executive officers, Ms. Greene and Mr. Kuczynski were not retirement-eligible on December 31, 2014.

		Retirement ($)		Resignation or Involuntary Termination		Death (payments to a spouse) ($)
T. A. Fanning	Pension		8,207		treated as retiring		4,998
	SBP-P		1,239,797		treated as retiring		1,239,797
	SERP		506,098		treated as retiring		506,098
A. P. Beattie	Pension		10,689		treated as retiring		5,740
	SBP-P		568,034		treated as retiring		568,034
	SERP		219,450		treated as retiring		219,450
W. P. Bowers	Pension		8,737		treated as retiring		5,256
	SBP-P		640,352		treated as retiring		640,352
	SERP		210,117		treated as retiring		210,117
K. S. Greene	Pension		—		628		1,031
	SBP-P		—		192,311		22,072
	SERP		—		—		29,307
S. E. Kuczynski	Pension		—		—		406
	SBP-P		—		—		—
	SERP		—		—		—

66  SOUTHERN COMPANY

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, 2014 following a change-in-control-related event, other than a Company Change-in-Control I (which does not impact how pension benefits are paid), are itemized below. These amounts would be paid instead of the benefits shown in the Traditional Termination Events chart above; they are not paid in addition to those amounts.

	SBP-P ($)		SERP ($)		Total ($)
T. A. Fanning		12,397,974		5,060,983		17,458,957
A. P. Beattie		5,680,337		2,194,503		7,874,840
W. P. Bowers		6,403,519		2,101,171		8,504,690
K. S. Greene		188,182		249,865		438,047
S. E. Kuczynski		—		—		—

The pension benefit amounts in the tables above were calculated as of December 31, 2014 assuming payments would begin as soon as possible under the terms of the plans. Accordingly, appropriate early retirement reductions were applied. Any unpaid annual performance-based compensation was assumed to be paid at 1.30 times the target level. Pension Plan benefits were calculated assuming each named executive officer chose a single life annuity form of payment, because that results in the greatest monthly benefit. The single sum values were based on a 3.79% discount rate.

Annual Performance Pay Program

The amount payable if a change in control had occurred on December 31, 2014 is the greater of target or actual performance. Because actual payouts for 2014 performance were above the target level for all of the named executive officers, the amount that would have been payable was the actual amount paid as reported in the CD&A and the Summary Compensation Table.

  SOUTHERN COMPANY  67

Stock Options, Performance Shares, and Restricted Stock Units (Equity Awards)

Equity Awards would be treated as described in the Termination and Change-in-Control charts above. Under a Southern Company Termination, all Equity Awards vest. In addition, if there is an Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason, Equity Awards vest. There is no payment associated with Equity Awards unless there is a Southern Company Termination and the participants’ Equity Awards cannot be converted into surviving company awards. In that event, the value of outstanding Equity Awards would be paid to the named executive officers. For stock options, the value is the excess

of the exercise price and the closing price of Common Stock on December 31, 2014. The value of performance shares and restricted stock units is calculated using the closing price of Common Stock on December 31, 2014. The chart below shows the number of stock options for which vesting would be accelerated under a Southern Company Termination and the amount that would be payable under a Southern Company Termination if there were no conversion to the surviving company’s stock options. It also shows the number and value of performance shares and restricted stock units that would be paid.

	Number of Equity Awards with Accelerated Vesting (#)						Total Number of Equity Awards Following Accelerated Vesting (#)						Total Payable in Cash without Conversion of Equity Awards ($)
	Stock Options		Performance Shares		Restricted Stock Units		Stock Options		Performance Shares		Restricted Stock Units
T. A. Fanning		1,700,767		167,393		—		2,337,096		167,393		—		22,658,723
A. P. Beattie		453,576		44,425		—		755,968		44,425		—		7,582,510
W. P. Bowers		552,123		54,423		—		1,406,893		54,423		—		17,029,625
K. S. Greene		432,135		18,700		46,425		541,840		18,700		46,425		5,643,939
S. E. Kuczynski		343,802		33,846		30,931		805,398		33,846		30,931		9,081,360

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.

Healthcare Benefits

All of the named executive officers, except Ms. Greene and Mr. Kuczynski, are retirement-eligible. Healthcare benefits are provided to retirees, and there is no incremental payment associated with the termination or change-in-control events, except in the case of a change-in-control-related termination, as described in

the Change-in-Control-Related Events chart. The estimated cost of providing healthcare insurance premiums for up to a maximum of three years is $44,826 for Ms. Greene and $45,975 for Mr. Kuczynski.

Financial Planning Perquisite

An additional year of the financial planning perquisite, which is set at a maximum of $8,700 per year, will be provided after retirement for retirement-eligible named executive officers.

There are no other perquisites provided to the named executive officers under any of the traditional termination or change-in-control-related events.

Severance Benefits

The named executive officers are participants in a change-in-control severance plan. The plan provides severance benefits, including outplacement services, if within two years of a change in control, they are involuntarily terminated, not for cause, or they voluntarily

68  SOUTHERN COMPANY

terminate for Good Reason. The severance benefits are not paid unless the named executive officer releases the employing company from any claims he or she may have against the employing company.

The estimated cost of providing the six months of outplacement services is $6,000 per named executive officer. The severance payment is three times the base salary and target payout under the annual Performance Pay Program for Mr. Fanning and two times the base salary and target payout under the annual Performance Pay Program for the other named executive officers. If any portion of the severance amount constitutes an “excess parachute payment” under Section 280G of the Code and is therefore subject to an excise tax, the severance amount will be reduced unless the after-tax “unreduced

amount” exceeds the after-tax “reduced amount.” Excise tax gross-ups will not be provided on change-in-control severance payments.

The table below estimates the severance payments that would be made to the named executive officers if they were terminated as of December 31, 2014 in connection with a change in control.

	Severance Amount ($)
T. A. Fanning		7,920,000
A. P. Beattie		2,357,242
W. P. Bowers		2,755,683
K. S. Greene		2,210,000
S.E. Kuczynski		2,272,536

COMPENSATION RISK ASSESSMENT

The Company reviewed its compensation policies and practices and concluded that excessive risk-taking is not encouraged. This conclusion was based on an assessment of the mix of pay components and performance goals, the annual pay/performance analysis by the Compensation Committee’s independent consultant, stock ownership requirements, compensation governance practices, and the claw-back provision. The assessment was reviewed with the Compensation Committee.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Compensation Committee is made up of independent Directors of the Company who have never served as executive officers of the Company. During 2014, none of the Company’s executive officers served on the Board of Directors of any entities whose executive officers serve on the Compensation Committee.

  SOUTHERN COMPANY  69

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information as of December 31, 2014 concerning shares of Common Stock authorized for issuance under Southern Company’s existing non-qualified equity compensation plans.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants, and rights (a)		Weighted-average exercise price of outstanding options, warrants, and rights (b)			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		39,929,319		$	40.55		15,179,865	(1)
Equity compensation plans not approved by security holders		n/a			n/a		n/a

(1) Represents shares available for future issuance under the Omnibus Incentive Compensation Plan.

70  SOUTHERN COMPANY

AUDIT

ITEM NO. 5 — RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Audit Committee of the Board of Directors is directly responsible for the appointment, retention, and oversight of the independent registered public accounting firm retained to audit the Company’s financial statements, including the compensation of such firm and the related audit fee negotiations.

Deloitte & Touche has served as the Company’s independent registered public accounting firm since 2002. To ensure continuing independence, the Audit Committee periodically considers whether there should be a change in the independent registered public accounting firm. The Audit Committee and its Chair also participate in the selection of Deloitte & Touche’s lead engagement partner in connection with the mandatory rotation requirements of the SEC.

The Audit Committee has appointed Deloitte & Touche as the Company’s independent registered public accounting firm for 2015. This appointment is being submitted to stockholders for ratification, and the Audit Committee and the Board of Directors believe that the continued retention of Deloitte & Touche to serve as the Company’s independent registered public accounting firm is in the best interests of the Company and its stockholders.

Representatives of Deloitte & Touche will be present at the 2015 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 the votes cast is required for ratification of the appointment of the independent registered public accounting firm.

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

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 2014 Annual Report to Stockholders attached hereto as Appendix D 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 (2013)” 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 the Public Company Accounting Oversight Board (PCAOB) Auditing Standard No. 16, Communications with Audit Committees and SEC Rule 2-07 of Regulation S-X, Communications with Audit Committees. 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

  SOUTHERN COMPANY  71

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 scope and plans with the Company’s internal auditors and independent registered public accounting firm for their respective audits. The Audit Committee meets with the internal auditors and the independent registered public accounting firm, with and without management present, to discuss the results of their audits, evaluations by management and the independent registered public accounting firm of the Company’s internal control over financial reporting, and the overall quality of the Company’s financial reporting. The Audit Committee also meets privately with the Company’s compliance officer. The Audit Committee held ten meetings during 2014.

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, 2014 and filed with the SEC. The Audit Committee also reappointed Deloitte & Touche as the Company’s independent registered public accounting firm for 2015. Stockholders will be asked to ratify that selection at the 2015 Annual Meeting.

Members of the Audit Committee as of December 31, 2014:

Jon A. Boscia, Chair

Juanita Powell Baranco

Warren A. Hood, Jr.

Larry D. Thompson

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 2014 and 2013.

	2014		2013
	(in thousands)
Audit Fees (1)	$	11,794	$	11,704
Audit-Related Fees (2)		126		110
Tax Fees		—		50
All Other Fees (3)		191		29
Total	$	12,111	$	11,893

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

(2) Includes non-statutory audit services in both 2014 and 2013.

(3) Represents registration fees for attendance at Deloitte & Touche-sponsored education seminars in 2013 and 2014, subscription fees for Deloitte & Touche’s technical accounting research tool in 2013 and 2014, information technology consulting services related to general ledger software of the Company in 2014, and travel expenses for Deloitte & Touche’s training facilitator in 2013.

The Audit Committee has adopted a Policy on Engagement of the Independent Auditor for Audit and Non-Audit Services (see Appendix C) 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.

72  SOUTHERN COMPANY

STOCKHOLDER PROPOSALS

ITEM NO. 6 — STOCKHOLDER PROPOSAL ON PROXY ACCESS

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

The Company has been advised that a stockholder proposes to submit the following resolution at the 2015 Annual Meeting. The name, address, and beneficial ownership of such stockholder are available upon request.

“RESOLVED: Shareholders of The Southern Company (the “Company”) ask the board of directors (the “Board”) to adopt, and present for shareholder approval, a “proxy access” bylaw. Such a bylaw shall require the Company to include in proxy materials prepared for a shareholder meeting at which directors are to be elected the name, Disclosure and Statement (as defined herein) of any person nominated for election to the board by a shareholder or group (the “Nominator”) that meets the criteria established below. The Company shall allow shareholders to vote on such nominee on the Company’s proxy card.

“The number of shareholder-nominated candidates appearing in proxy materials shall not exceed one quarter of the directors then serving. This bylaw, which shall supplement existing rights under Company bylaws, should provide that a Nominator must:

a) have beneficially owned 3% or more of the Company’s outstanding common stock continuously for at least three years before submitting the nomination;

b) give the Company, within the time period identified in its bylaws, written notice of the information required by the bylaws and any Securities and Exchange Commission rules about (i) the nominee, including consent to being named in the proxy materials and to serving as director if elected; and (ii) the Nominator, including proof it owns the required shares (the “Disclosure”); and

c) certify that (i) it will assume liability stemming from any legal or regulatory violation arising out of the Nominator’s communications with the Company shareholders, including the Disclosure and Statement; (ii) it will comply with all applicable laws and regulations if it uses soliciting material other than the Company’s proxy materials; and (c) to the best of its knowledge, the required shares were acquired in the ordinary course of business and not to change or influence control at the Company.

“The Nominator may submit with the Disclosure a statement not exceeding 500 words in support of the nominee (the “Statement”). The Board shall adopt procedures for promptly resolving disputes over whether notice of a nomination was timely, whether the Disclosure and Statement satisfy the bylaw and applicable federal regulations, and the priority to be given to multiple nominations exceeding the one-quarter limit.

SUPPORTING STATEMENT

“We believe proxy access is a fundamental shareholder right that will make directors more accountable and contribute to increased shareholder value. The CFA Institute’s 2014 assessment of pertinent academic studies and the use of proxy access in other markets similarly concluded that proxy access:

¡ Would “benefit both the markets and corporate boardrooms, with little cost or disruption.”

  SOUTHERN COMPANY  73

¡ Has the potential to raise overall US market capitalization by up to $140.3 billion if adopted market-wide. (http://www.cfapubs.org/doi/pdf/10.2469/ccb.v2014.n9.1)

“The proposed bylaw terms enjoy strong investor support — votes for similar shareholder proposals averaged 55% from 2012 through September 2014 — and similar bylaws have been adopted by companies of various sizes across industries, including Chesapeake Energy, Hewlett-Packard, Western Union and Verizon.

“We urge shareholders to vote FOR this proposal.”

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

Proxy access, which refers to the ability of stockholders holding a small percentage of the Company’s shares to require the Company to undertake the effort and expense of including their Director nominees in the Company’s proxy materials and thus trigger a proxy contest, is an untested governance feature for U.S. companies. The Board of Directors continually evaluates the Company’s governance profile and believes that proxy access should not be implemented in the absence of a compelling rationale. The proponent’s proxy access proposal does not seek to remedy any specific governance or performance deficiency at the Company; in fact, it appears the Company was targeted with this proposal solely because its business involves the consumption of fossil fuels and not because of any development related to proxy access.

The Company’s stockholders already have significant and meaningful corporate governance rights. This includes the ability to recommend Director candidates for independent consideration by the Governance Committee and the ability to register disapproval of individual Directors or the full Board, on an annual basis, by means of the Company’s majority voting standard and Director resignation policy. In addition, stockholders holding as few as 10% of the outstanding shares of Common Stock have the right to request a special meeting of stockholders.

Southern Company has consistently created value for its stockholders and there is no need for proxy access.

¡ The most recent dividend, paid March 6, 2015, marks the 269th consecutive quarter the Company has paid a dividend equal to or higher than the previous quarter.

¡ The Southern Company generation system’s Equivalent Forced Outage Rate is at industry-leading levels (1.9% compared to five-year national average of approximately 9.0%).

¡ The Company and its four traditional operating company subsidiaries occupied the top five spots for customer satisfaction for all customer classes combined in the customer value benchmark survey, an annual peer comparison of U.S. electric utilities.

¡ With respect to compensation matters, the Company has received stockholder support in its annual say-on-pay vote of in excess of 94% of votes cast since the vote was first held in 2011.

Southern Company stockholders already have access to robust and effective procedures to communicate with and influence the Board of Directors and hold it accountable.

¡ The full Board of Directors is elected annually and the Company has a majority voting standard in uncontested Director elections, combined with a resignation policy for candidates who fail to receive a majority of votes cast (see page 13).

¡ Management proactively engages with stockholders on corporate governance issues (see page 12).

¡ The Company holds an annual say-on-pay vote on executive compensation (see page 24).

74  SOUTHERN COMPANY

¡ The Board of Directors has established a mechanism for stockholders to directly communicate with the Board or with specified Directors (see page 12).

¡ The Company regularly engages with stockholders and other concerned parties on environmental issues and has provided significant voluntary disclosure.

Southern Company already has significant corporate governance practices that protect stockholder rights and interests.

¡ The Company has a threshold of just 10% of outstanding shares for stockholders to request a special meeting.

¡ Stockholders must approve amendments to the Company’s certificate of incorporation and By-Laws, so the Board of Directors cannot unilaterally take away any rights granted to stockholders in the Company’s governing documents.

¡ The Company has not adopted a “poison pill” stockholder rights plan and the Board of Directors does not have the authority to issue “blank check” preferred stock.

¡ If Proposal No. 3 is approved by stockholders, the Company’s certificate of incorporation and By-Laws will not restrict stockholders’ ability to act by written consent to the fullest extent allowed by applicable Delaware law (see page 9).

The Board of Directors is already highly-qualified, diverse, and independent.

All members of the Board of Directors, other than the Chief Executive Officer, are independent of management and the Board has a strong Lead Independent Director to provide a source of independent leadership (see page 15). The Board periodically refreshes its membership to ensure it adds helpful experience and fresh perspectives and maintains appropriate diversity. Since the beginning of 2014, the Board of Directors has added three new members – Ms. Hudson and Messrs. Thompson and Johns, which means the Board now includes three female members and three ethnic minorities. The Board’s commitment to refreshment is reflected in its overall average Board tenure, which is less than six years.

Implementing proxy access could negatively affect the Company’s corporate governance.

Bypassing the independent Governance Committee process for nominations.

Implementing proxy access would provide a small percentage of stockholders, who do not have a fiduciary obligation to other stockholders and who may have a narrow agenda, the right to include Director nominees in the Company’s proxy statement, bypassing the Company’s independent nomination process. Currently, absent a proxy contest, all nominees are recommended to the full Board of Directors for nomination by the Governance Committee. Stockholders may participate in this process by submitting recommendations of candidates for consideration by the Governance Committee (see page 19). The Governance Committee is composed entirely of independent Directors, and the Board and the Governance Committee each have a fiduciary duty to make nominations that are in the best interests of all stockholders. The Board of Directors and the Governance Committee are in the best position to evaluate Director candidates, in light of the need for a full Board that is composed of a group of Directors with complementary skills, experience, and perspectives and that meets the unique needs of the Company.

Increasing the influence of special interests and fragmenting the Board of Directors.

If proxy access were implemented, a small minority of stockholders could nominate Director candidates to further a special interest agenda that may not be in the best interest of the Company as a whole. Opposing such candidates in a contested election would be time-consuming and costly for the

  SOUTHERN COMPANY  75

Company. Accordingly, even if special interest Directors were not elected, such stockholders could still attempt to use proxy access to extract concessions from the Company related to their special interests. Moreover, the election of Directors nominated by a small percentage of stockholders with special interests could also result in the creation of factions on the Board of Directors, making it more difficult for the Board to reach consensus on behalf of all stockholders, thereby delaying important decision-making.

Proxy access could lead to continually contested elections, which would impose costs on the Company, divert management’s and the Board’s attention, and potentially discourage highly-qualified Directors from serving.

Providing proxy access for a group of stockholders owning just 3% of the Company’s outstanding shares could make contested elections much more commonplace. Currently, stockholders seeking to nominate Director candidates must, like the Company, bear their own costs of soliciting votes for their proposed nominees. This existing system helps ensure that a stockholder is serious about its intention to nominate Directors, because the stockholder must bear the cost of its own solicitation. Proxy access would shift this cost to the Company, at no risk to the stockholder. In addition, the prospect of having to stand in a contested election routinely could cause highly-qualified Directors to be reluctant to serve on the Board of Directors.

The vote needed to pass the proponent’s resolution is the affirmative vote of a majority of the votes cast.

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

ITEM NO. 7 — GREENHOUSE GAS EMISSIONS REDUCTION GOALS 2015

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

The Company has been advised that a stockholder, together with multiple co-filers, proposes to submit the following resolution at the 2015 Annual Meeting. The names, addresses, and beneficial ownership of such stockholder and co-filers are available upon request.

RESOLVED:

“Shareholders request that Southern Company adopt absolute, quantitative time-bound goals for reducing total greenhouse gas (GHG) emissions from operations and report to shareholders by November 1, 2015 on its plans to achieve these goals (omitting proprietary information and prepared at reasonable cost.)”

WHEREAS:

“The 2014 Synthesis Report of the Intergovernmental Panel on Climate Change (IPCC) warns that continued greenhouse gas (GHG) emissions and subsequent global warming will have “severe, pervasive and irreversible impacts for people and ecosystems.” The Risky Business report forecasts significant economic costs to agriculture, labor productivity, and property.

“To mitigate the worst impacts of climate change and limit warming to below 2°C, as agreed in the Copenhagen Accord, the IPCC estimates that a fifty percent reduction in GHG emissions globally is needed by 2050, relative to 1990 levels.

“Our country’s fleet of fossil fueled power plants is the single largest source of carbon pollution in the U.S., accounting for over one-third of total carbon emissions, according to the Environmental Protection Agency (EPA.) Plans for increased regulation of GHG emissions are already underway, posing regulatory risk to the company. President Obama committed to reduce emissions by 26-28

76  SOUTHERN COMPANY

percent by 2025. The EPA’s Clean Power Plan would strengthen emissions standards for power plants, seeking an overall 30 percent reduction of CO2 emissions by 2030. With the fourth highest power generation from burning coal in the country and the third highest level of carbon emissions of U.S. power producers, compliance with this rule will likely require substantial adjustments to Southern facilities, entailing emissions reductions, increased use of renewable energy and deployment of energy efficiency. Meanwhile, Southern has publicly stated that it does not support this regulation.

“Southern Company has made significant investments in renewable energy, efficiencies, and a more diversified energy mix. Setting clear proactive goals to manage greenhouse gas emissions at Southern Company and its operating companies would enable the Company to manage climate risk and align with a growing global commitment to contain emissions. Sixty percent of Fortune 100 companies have set GHG reduction goals or renewable energy targets. Southern lags behind peers including American Electric Power, CMS Energy, Exelon and Duke Energy which have set absolute and/or intensity carbon reduction goals. NRG Energy announced its aim to reduce its carbon emissions 50 percent by 2030 and 90 percent by 2050.

SUPPORTING STATEMENT:

“A disciplined business strategy to cut emissions includes setting goals, striving to meet them and reporting on progress. Leading practices for electric utilities to manage carbon across the enterprise include pursuing all cost-effective energy efficiency opportunities, deploying large-scale and distributed renewable energy, utilizing smart grid technologies for consumer and system benefit, and serving as a systems integrator providing services to meet varying customer needs; and conducting robust and transparent resource planning. Two commonly used options for setting GHG targets are GHG “intensity” or “absolute” targets. Absolute GHG reduction goals compare total GHG emissions in the goal year to those in a base year.”

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

The Board of Directors does not believe it is in the best interests of the Company or its stockholders at this time to establish voluntary, absolute quantitative goals for reducing total greenhouse gas (GHG) emissions from the Southern Company system’s operations. Independently establishing these types of goals would not add value to the Company’s already robust research, development, and deployment efforts relating to new technology to reduce GHG emissions, would be premature given the Environmental Protection Agency’s (EPA) proposed regulations relating to GHG emissions from new and existing sources, and would not be an efficient use of additional Company resources given the ongoing reporting and significant policy engagement by the Company in this area.

The Southern Company system is committed to a diverse energy mix. With a strong base of natural gas, coal, nuclear, hydro, and growing renewable generating capacity, the Southern Company system’s fleet is flexible, allowing it to choose the most cost effective fuel source to best serve customers with clean, safe, reliable, and affordable energy. The Southern Company system is dedicated to a full portfolio of resources for the United States’ energy future — twenty-first century coal, natural gas, renewables, new nuclear, and energy efficiency.

Currently, the EPA is in the process of promulgating carbon dioxide regulations that will affect new, existing, and modified and reconstructed power plants. Final emission standards for new sources and for modified and reconstructed sources and final emission reduction guidelines for existing sources are expected this year from the EPA. Independently establishing reduction goals without the benefit of these final rules is premature. Even absent regulations, the Southern Company system’s GHG emissions in 2014 were almost 20% lower than 2005 levels.

  SOUTHERN COMPANY  77

The Southern Company system is a leader in the industry in developing technologies to reduce GHG emissions in the generation of electric energy and has committed substantial financial and human resources to research, develop, and deploy such technologies. This leadership is best evidenced by the Southern Company system’s efforts to develop carbon capture and storage. The Southern Company system was selected by the U.S. Department of Energy (DOE) to manage and operate the DOE’s National Carbon Capture Center in Alabama, a focal point of national efforts to reduce GHG emissions from coal-based power plants through technological innovation. Additionally, the Company has joined the DOE and other partners to demonstrate carbon capture and storage at a coal-based power plant in Alabama. The Company and its partners have developed an advanced coal gasification technology known as Transport Integrated Gasification (TRIG^TM) designed to produce less carbon dioxide emissions than the current fleet of existing coal plants. The Company’s subsidiary, Mississippi Power, is constructing the Kemper IGCC using TRIG^TM technology, which is designed to include the capture and sequestration (via enhanced oil recovery) of at least 65 percent of the carbon dioxide produced by the Kemper IGCC during operations.

Additionally, as nuclear power re-emerges as a viable way to meet new demand for electricity, with the added benefit of no emissions of GHG, Southern Company, through its subsidiary Georgia Power, is leading the nation’s nuclear energy renaissance with the construction of two new nuclear units at Plant Vogtle.

The Company has created a number of reports disclosing its actions related to GHG and other emissions. In 2006, the Company’s long-standing Environmental Progress Reports evolved into its Corporate Responsibility Report, which includes data on emissions and actions being undertaken to address those emissions. Additionally, the Company has also published for a number of years its climate and carbon disclosure reports, which describe specific current and long-term activities to address GHG emissions. The reports are updated on an annual basis. These reports are available either through the Company’s external website at http://www.southerncompany.com/what-doing/corporate-responsibility/home.cshtml or by contacting Melissa K. Caen, Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308 and requesting a copy.

For a number of years, the Company also has actively engaged its stakeholders regarding environmental matters affecting the Southern Company system. Since 2011, the Company has held environmental stakeholder forums, webinars, calls, and meetings covering a range of topics from regulatory and policy issues and system risk and planning to renewables, energy efficiency, and GHG issues.

In summary, the Board of Directors does not believe it is in the best interests of the Company or its stockholders to independently establish at this time voluntary, absolute quantitative goals for reducing total GHG emissions from the Southern Company system’s operations due to (1) the Southern Company system’s already robust research, development, and deployment efforts relating to new technology to reduce GHG emissions, (2) the EPA’s pending regulations governing GHG emissions from new and existing sources, which are not yet finalized, and (3) the Company’s ongoing practice of reporting emissions data, emission reduction results, investment, and significant policy engagement. A separate report as requested in the proposal regarding plans to achieve such goals would not be an efficient use of additional Company resources or add value to the Company’s current efforts in this area.

The vote needed to pass the proponents’ resolution is the affirmative vote of a majority of the votes cast.

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

78  SOUTHERN COMPANY

OTHER INFORMATION

FREQUENTLY ASKED QUESTIONS

Q: When will the Proxy Statement be mailed?

A: The Proxy Statement will be mailed on or about April 10, 2015.

Q: Who is entitled to vote?

A: All stockholders of record at the close of business on the record date of March 30, 2015 may vote.

Q: How do I give voting instructions?

A: You may attend the meeting and give instructions in person or give instructions by internet, by phone, or by mail. Information for giving instructions is on the form of proxy and trustee voting instruction form (proxy form). For those investors whose shares are held by a broker, bank, or other nominee, you must complete and return the voting instruction form provided by your broker, bank, or nominee in order to instruct your broker, bank, or nominee on how to vote. The Proxies, named on the enclosed proxy form, will vote all properly executed proxies that are delivered pursuant to this solicitation and not subsequently revoked in accordance with the instructions given by you.

Q: Why is my vote important?

A: It is the right of every investor to vote on certain matters that affect the Company.

Q: Can I change my vote?

A: Yes. If you are a holder of record, you may revoke your proxy by submitting a subsequent proxy, or by written request received by the Company’s Corporate Secretary prior to the meeting, or by attending the meeting and voting your shares. If your shares are held through a broker, bank, or other nominee, you must follow the instructions of your broker, bank, or other nominee to revoke your voting instructions.

Q: How are votes counted?

A: Each share counts as one vote. A quorum is required to transact business at the 2015 Annual Meeting. Stockholders of record holding shares of stock constituting a majority of the shares entitled to be cast shall constitute a quorum. Abstentions that are marked on the proxy form and broker non-votes are included for the purpose of determining a quorum, but shares that otherwise are not voted are not counted toward a quorum. Neither abstentions, broker non-votes, nor shares that otherwise are not voted are counted for or against each of the matters being considered at the 2015 Annual Meeting and thus will not affect the outcome of the vote for these items, except that abstentions will have the same effect as votes “against” Item No. 3.

Q: What are broker non-votes?

A: Broker non-votes occur on a matter up for vote when a broker, bank, or other holder of shares you own in “street name” is not permitted to vote on that particular matter without instructions from you, you do not give such instructions, and the broker, bank, or other nominee indicates on its proxy form, or otherwise notifies the Company, that it does not have authority to vote its shares on that matter. Whether a broker has authority to vote its shares on uninstructed matters is determined by NYSE rules.

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 of your shares are voted. If you wish to consolidate multiple registered accounts, please contact Shareowner Services at Computershare Inc. at (800) 554-7626.

  SOUTHERN COMPANY  79

Q: Can the Proxy Statement be accessed from the internet?

A: Yes. You can access the Company’s website at http://investor.southerncompany.com/proxy to view the Proxy Statement.

Q: How do I attend the 2015 Annual Meeting in person?

A: All attendees need to bring photo identification, such as a driver’s license, to gain admission to the 2015 Annual Meeting. If you are a holder of record, the top half of your proxy card is your admission ticket. If you hold your shares in street name, you will need proof of ownership to be admitted to the meeting. Examples of proof of ownership are a recent brokerage statement or a letter from your bank or broker. If you want to vote your shares held in street name, you must get a legal proxy in your name from the broker, bank, or other nominee that holds your shares. Please note that cameras, sound or video recording equipment, cellular telephones, smartphones or other similar equipment, and electronic devices are not permitted to be used during the 2015 Annual Meeting.

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

A: Yes. Most stockholders can elect to receive an email that will provide an electronic link to the Proxy Statement, which includes the 2014 Annual Report as an appendix. Opting to receive your proxy materials on-line will save the Company 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 by visiting www.icsdelivery.com/so. 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 2014 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: Stockholders sharing a single address may receive only one copy of the Proxy Statement, which includes the 2014 Annual Report as an appendix, unless the transfer agent, broker, bank, or other nominee has received contrary instructions from any owner at that address. This practice — known as householding — is designed to reduce printing and mailing costs. If a stockholder of record would like to either participate or cancel participation in householding, he or she may contact Shareowner Services at Computershare Inc. at (800) 554-7626 or by mail at The Southern Company, c/o Computershare, P.O. Box 30170, College Station, TX 77842-3170. If you own indirectly through a broker, bank, or other nominee, please contact your financial institution.

Q: What is the Board’s recommendation for the proposals?

A: The Board of Directors recommends votes “FOR” each of Item Nos. 1, 2, 3, 4, and 5 and votes “AGAINST” Item Nos. 6 and 7 in this Proxy Statement.

Q: How many votes are needed to approve each of the items of business?

A: The affirmative vote of a majority of the votes cast is required for approval of each of Item Nos. 1, 2, 4, 5, 6, and 7. For Item No. 3, the affirmative vote of a majority of the shares represented in person or by proxy and entitled to vote at the 2015 Annual Meeting is required for approval.

Q: When are stockholder proposals due for the 2016 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 2016

80  SOUTHERN COMPANY

Annual Meeting of Stockholders is December 12, 2015. Proposals must be submitted in writing to Melissa K. Caen, 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 25, 2016.

Q: Who is soliciting these proxies and who pays the expense of such solicitations?

A: These proxies are being solicited on behalf of the Company’s Board of Directors. The Company pays the cost of soliciting proxies. The Company has retained Georgeson Inc. to assist with the solicitation of proxies for a fee of $12,500, plus additional fees for telephone and other solicitation of proxies or other services, if needed, and reimbursement of out-of-pocket expenses. The officers or other employees of the Company or its subsidiaries may solicit proxies to have a larger representation at the meeting. None of these officers or other employees of the Company will receive any additional compensation for these services. Upon request, the Company will reimburse brokerage houses and other custodians, nominees, and fiduciaries for their reasonable out-of-pocket expenses for forwarding solicitation material to the beneficial owners of the Company’s common stock.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Based on the Company’s review of Forms 3, 4, and 5 and amendments thereto in the Company’s possession and written representations furnished to the Company, the Company believes that no reporting person of the Company failed to file, on a timely basis, the reports required by Section 16(a) of the Securities Exchange Act of 1934, as amended, except for an inadvertent late filing of a Form 4 to disclose one transaction by David J. Grain.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Mr. Donald M. James, a Director of the Company, served as the Chief Executive Officer of Vulcan Materials Company from 1997 to 2014. During 2014, subsidiaries of the Company purchased approximately $2.1 million of goods and services from Vulcan Materials Company and its affiliates, primarily related to on-going construction projects.

Mr. E. Jenner Wood III, a Director of the Company, is Chairman, President, and Chief Executive Officer of the Atlanta Division of SunTrust Bank and Executive Vice President of SunTrust Banks, Inc. During 2014, subsidiaries of the Company made payments of approximately $1.1 million to certain subsidiaries of SunTrust Banks, Inc., substantially related to aircraft leases.

During 2014, certain subsidiaries of SunTrust Banks, Inc. also furnished a number of regular banking services in the ordinary course of business to the Company and its subsidiaries and served as an underwriter for certain securities offerings of the Company and its subsidiaries for which $1.7 million was received by these certain subsidiaries of SunTrust Banks, Inc. The Company and its subsidiaries intend to maintain normal banking relations with SunTrust Banks, Inc. and its subsidiaries in the future.

The Company does not have a written policy pertaining solely to the approval or ratification of “related party transactions.” The Company has a Code of Ethics as well as a Contract 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. The approval and ratification of any related party transactions would be subject to these written policies and procedures which include a determination of the need for the goods and services; preparation and evaluation of requests for proposals by supply chain management; the writing of contracts; controls and guidance regarding the evaluation of the proposals; and negotiation of contract terms and conditions. As appropriate, these

  SOUTHERN COMPANY  81

contracts are also reviewed by individuals in the legal, accounting, and/or risk management/services departments prior to being approved by the responsible individual. The responsible individual will vary depending on the

department requiring the goods and services, the dollar amount of the contract, and the appropriate individual within that department who has the authority to approve a contract of the applicable dollar amount.

82  SOUTHERN COMPANY

APPENDIX A

OUTSIDE DIRECTORS STOCK PLAN

OUTSIDE DIRECTORS STOCK PLAN FOR

THE SOUTHERN COMPANY AND ITS SUBSIDIARIES

  SOUTHERN COMPANYA-1

Outside Directors Stock Plan for The Southern Company and its Subsidiaries

Article I—Purpose and Adoption of Plan

1.1 Adoption. The Southern Company hereby adopts the Outside Directors Stock Plan for The Southern Company and Its Subsidiaries, effective June 1, 2015 subject to (a) the approval of the Plan by the stockholders of the Company at the annual meeting thereof to be held on May 27, 2015 and (b) registration of the Stock to be issued pursuant to the Plan.

1.2 Purpose. The Plan is designed to more closely align the interests of Directors with the interests of the stockholders of the Company through ownership of Stock.

Article II—Definitions

2.1 “Affiliated Employer” shall mean any corporation which is a member of the controlled group of corporations of which the Company is the common parent corporation.

2.2 “Board of Directors” shall mean either the Southern Board or a System Company Board, as applicable to a Director.

2.3 “Commission” shall mean the Securities and Exchange Commission.

2.4 “Company” shall mean The Southern Company.

2.5 “Company Board” shall mean the Board of Directors of The Southern Company.

2.6 “Director” shall mean any person who is not an active employee of the Company or a System Company and who either serves on the Company Board or a System Company Board.

2.7 “Effective Date” shall mean June 1, 2015.

2.8 “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

2.9 “Market Value” shall mean the following:

(a) With respect to Stock that is issued by the Company, the closing price of the Stock, as published in the Wall Street Journal in its report of New York Stock Exchange composite transactions, on the date such Market Value is to be determined, as specified herein.

(b) With respect to Stock that is purchased on the open market, the actual purchase price paid for the Stock on the date purchased.

2.10 “Participant” shall mean each Director who meets the requirements of Section 3.1 of the Plan.

2.11 “Plan” shall mean the Outside Directors Stock Plan for The Southern Company and Its Subsidiaries, as amended from time to time.

2.12 “Plan Administrator” shall mean the Governance Committee of the Company Board.

2.13 “Plan Year” shall mean the calendar year.

2.14 “Retainer Fee” shall mean the annual rate of the fees paid to a Director as determined by the Board of Directors from time-to-time, but excluding reimbursements for expenses and any additional fees or compensation for (a) attendance at the meetings of the Board of Directors or any committee, (b) service on a committee and (c) service at the request of the Board of Directors or a committee.

2.15 “Stock” shall mean the Company’s common stock, par value $5.00 per share.

2.16 “System Company” shall mean any Affiliated Employer which adopted the Outside Directors Stock Plan for Directors of The Southern Company and its Subsidiaries that was effective May 26, 2004 and any additional Affiliated Employer the Company Board may from time to time determine to bring under the Plan and which shall adopt the Plan. The System Companies that have adopted the Plan are listed in Schedule A, attached hereto, as such Schedule may be amended from time to time.

2.17 “System Company Board” shall mean the Board of Directors of a System Company.

The masculine pronoun shall be construed to include the feminine pronoun and the singular shall include the plural, where the context so requires.

A-2  SOUTHERN COMPANY

Article III—Eligibility

3.1 Eligibility Requirements.

(a) Except as provided in Subsection (b), each Director shall become a Participant in the Plan on the first date such Director serves on the Board of Directors.

(b) For purposes of the 2015 Plan Year, a Director who is serving on a Board of Directors as of the Effective Date shall become a Participant in the Plan on the Effective Date.

Article IV—Form and Time of Benefit Distributions

4.1 Stock Grant. Each Participant shall receive a portion of his Retainer Fee in Stock. Any remainder of such Retainer Fee and any meeting attendance fees, in increments elected by the Director in accordance with Section 4.2, may be paid in cash or in Stock. The portion of the Retainer Fee required to be paid in Stock pursuant to this Section 4.1 may be denominated in dollars or a fixed number of shares of Stock and shall be stated in Schedule B, attached hereto, as such Schedule shall be amended from time to time by the Board of Directors.

4.2 Election to Determine Percentage or Amount of Compensation to be Paid in Stock. Prior to the beginning of each Plan Year, each Participant shall have an opportunity to elect to have the non-Stock portion of his Retainer Fee paid in cash or Stock of the Company, or a combination thereof. Each Participant also shall have an opportunity to elect to have a portion of any meeting attendance fees paid in Stock. Nothing contained in this Section 4.2 shall be interpreted in such a manner as would disqualify the Plan from treatment as a “formula plan” under Rule 16b-3, as promulgated by the Commission under the Exchange Act, as that rule may be amended from time to time.

4.3 Amount of Stock Compensation Denominated in Dollars. For Stock compensation that is denominated in dollars, the number of shares of Stock due to a Participant, including any fractional shares, shall be determined by dividing the prescribed dollar amount by the Market Value on the compensation payment date.

4.4 Deferral of Stock Compensation. Any portion of the Retainer Fee that is required to be paid in Stock pursuant to Section 4.1 may be deferred in accordance with the terms of the Deferred Compensation Plan maintained by the Company or System Company for its Directors. Any other Director compensation that a participant may elect to receive in Stock under the Plan may be similarly deferred.

4.5 Death Benefits. No grants of Stock shall be made to any beneficiary of a Participant following a Participant’s death.

Article V—Administration of Plan

5.1 Administrator. The general administration of the Plan shall be the responsibility of the Plan Administrator.

5.2 Powers. The Plan Administrator shall administer the Plan

(a) The Plan Administrator shall administer the Plan in accordance with its terms and shall have all powers necessary to carry out the provisions of the Plan. It shall interpret the Plan and shall have the discretion to determine all questions arising in the administration, interpretation and application of the Plan, including any ambiguities contained herein or any questions of fact. Any such determination by it shall be conclusive and binding on all persons. It may adopt such procedures as it deems desirable for the conduct of its affairs. It may appoint such accountants, counsel, actuaries, specialists and other persons as it deems necessary or desirable in connection with the administration of the Plan, and shall be the agent for the service of process.

(b) The Plan Administrator may delegate to such officers, employees or departments of the Company or an affiliate of the Company, such authority, duties and responsibilities of the Plan Administrator as it, in its sole discretion, considers necessary or appropriate for the proper and efficient operation of the Plan, including, without limitation, interpretation of the Plan and establishment of procedures for administration of the Plan.

5.3 Indemnification. The System Companies and the Company shall indemnify the Plan Administrator against any and all claims, losses, damages, expenses and liability arising from any action or failure to act, except when the same is finally judicially determined to be due to gross negligence or willful misconduct. The System Companies and the Company may purchase at their own expense sufficient liability insurance for the Plan Administrator to cover any and all claims, losses, damages and expenses arising from any action or failure to act in connection with the execution of the duties as Plan Administrator.

  SOUTHERN COMPANYA-3

Article VI—Miscellaneous

6.1 Assignment. Neither the Participant nor his legal representative shall have any rights to sell, assign, transfer or otherwise convey the right to receive the payment of any benefit due hereunder, which payment and the right thereto are expressly declared to be nonassignable and nontransferable. Any attempt to assign or transfer the right to payment under the Plan shall be null and void and of no effect.

6.2 Amendment and Termination. The Plan may be wholly or partially amended or otherwise modified, suspended or terminated at any time by the Company Board or by its Governance Committee with the approval of the Company Board, upon execution of a duly authorized written document; provided, however, that, without the approval of the stockholders of the Company entitled to vote thereon, no amendment may be made which would, absent such stockholder approval, disqualify the Plan for coverage under Rule 16b-3, as promulgated by the Commission under the Exchange Act, as that rule may be amended from time to time. Notwithstanding the foregoing, no such amendment or termination shall impair any rights to payments to which a Participant may be entitled prior to the effective date of such amendment or termination.

6.3 No Guarantee of Continued or Future Service on a Board of Directors. Participation hereunder shall not be construed as creating a right in any Director to continued service or future service on the Board of Directors. Participation hereunder does not constitute an employment contract between any Director and any System Company or the Company as the case may be.

6.4 Construction. This Plan shall be construed in accordance with and governed by the laws of the State of Georgia, to the extent such laws are not otherwise superseded by the laws of the United States.

IN WITNESS WHEREOF, the Company Board, through its duly authorized officers, has adopted this Outside Directors Stock Plan for The Southern Company and Its Subsidiaries this 9^th day of February, 2015, to be effective as provided herein.

THE SOUTHERN COMPANY:
By:
Its:	Secretary

Attest:
By:
Its:	Assistant Secretary

Schedule A

The System Companies as of May 27, 2015 are:

Alabama Power Company

Georgia Power Company

Gulf Power Company

Mississippi Power Company

Schedule B

As of June 1, 2015

The portion of a Participant’s Retainer Fee required to be distributed in Stock shall be determined in accordance with the following schedule:

Company	Dollar Amount of Required Stock Distribution
Southern Company	$105,000
Alabama Power Company	$30,000
Georgia Power Company	$30,000
Gulf Power Company	$19,500
Mississippi Power Company	$19,500

A-4  SOUTHERN COMPANY

APPENDIX B

PROPOSED AMENDMENT TO SECTION 46 OF THE COMPANY’S BY-LAWS

The text of the proposed amendment to Section 46 of the Company’s By-Laws, marked to show changes to the current Section 46, is set forth as follows:

46. The By-Laws of the Corporation may be altered, amended or repealed (a) at any meeting of the Board of Directors by the vote of a majority of the entire Board then in office, or (b) by the vote of the holders of a majority of that part of the capital stock of the Corporation having voting powers which is represented in person or by proxy at any annual meeting of stockholders or at any special meeting called for that purpose (provided that a lawful quorum of stockholders be there represented in person or by proxy), or (c) without a meeting by the written consent of the holders of all of not less than the minimum number of the issued and outstanding shares of capital stock of the Corporation having voting powers that would be necessary to take such action at a meeting at which all shares entitled to vote thereon were present and voted; provided, however, that the Board of Directors shall not have power to alter, amend or repeal the provisions of Sections 5, 44 or 46 of the By-Laws and provided, further, that an alteration, amendment or repeal of any other provision of the By-Laws by the Board of Directors shall cease to be effective unless submitted to and ratified or approved at the next annual or special meeting at which a lawful quorum of stockholders is represented in person or by proxy by the vote of the holders of a majority of that part of the capital stock of the Corporation having voting powers which is represented in person or by proxy at such meeting.

  SOUTHERN COMPANYB-1

APPENDIX C

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

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

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

2. Financial information systems design and implementation.

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

4. Actuarial services.

5. Internal audit outsourcing services.

6. Management functions or human resources.

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

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

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

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

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

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

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

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

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

Approved by the Southern Company Audit Committee

December 9, 2002

  SOUTHERN COMPANYC-1

APPENDIX D

  SOUTHERN COMPANY

TABLE OF CONTENTS

Southern Company Common Stock and Dividend Information	D-ii
Five-Year Cumulative Performance Graph	D-ii
Twenty-Year Cumulative Performance Graph	D-iii
Management’s Report on Internal Control over Financial Reporting	D-1
Report of Independent Registered Public Accounting Firm	D-2
Management’s Discussion and Analysis of Financial Condition and Results of Operations	D-5
Cautionary Statement Regarding Forward-Looking Statements	D-34
Consolidated Statements of Income	D-36

Consolidated Statements of Comprehensive Income	D-37
Consolidated Statements of Cash Flows	D-38
Consolidated Balance Sheets	D-39
Consolidated Statements of Capitalization	D-41
Consolidated Statements of Stockholders’ Equity	D-43
Notes to Financial Statements	D-44
Selected Consolidated Financial and Operating Data	D-103
Management Council	D-105
Stockholder Information	D-107

  SOUTHERN COMPANYD-i

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
2014
First Quarter	$	44.00	$	40.27	$	0.5075
Second Quarter		46.81		42.55		0.5250
Third Quarter		45.47		41.87		0.5250
Fourth Quarter		51.28		43.55		0.5250
2013
First Quarter	$	46.95	$	42.82	$	0.4900
Second Quarter		48.74		42.32		0.5075
Third Quarter		45.75		40.63		0.5075
Fourth Quarter		42.94		40.03		0.5075

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, 2009 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.

D-ii  SOUTHERN COMPANY

TWENTY-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 20 years. The graph assumes that $100 was invested on December 31, 1994 in the Company’s common stock and each of the above indices and that all dividends were reinvested. The distribution of shares of Mirant Corporation stock to the Company’s stockholders in 2001 is treated as a special dividend for purposes of calculating the Company’s shareholder return. The stockholder return shown below for the twenty-year historical period may not be indicative of future performance.

  SOUTHERN COMPANYD-iii

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company and Subsidiary Companies 2014 Annual Report

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

Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) 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, 2014.

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, 2014. Deloitte & Touche LLP’s report on Southern Company’s internal control over financial reporting is included herein.

Thomas A. Fanning

Chairman, President, and Chief Executive Officer

Art P. Beattie

Executive Vice President and Chief Financial Officer

March 2, 2015

  SOUTHERN COMPANYD-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

The Southern Company

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. We also have audited the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) 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 D-1). Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

In our opinion, the consolidated financial statements (pages D-36 to D-101) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Atlanta, Georgia

March 2, 2015

D-2  SOUTHERN COMPANY

DEFINITIONS

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
APA	Asset purchase agreement
ASC	Accounting Standards Codification
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC’s authority to facilitate development and construction of baseload generation in the State of Mississippi
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
CO2	Carbon dioxide
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	IGCC facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MPUS	Mississippi Public Utilities Staff
MW	Megawatt
NCCR	Georgia Power’s Nuclear Construction Cost Recovery
NDR	Alabama Power’s Natural Disaster Reserve
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
Rate CNP	Alabama Power’s Rate Certificated New Plant
Rate CNP Environmental	Alabama Power’s Rate Certificated New Plant Environmental
Rate CNP PPA	Alabama Power’s Rate Certificated New Plant Power Purchase Agreement
Rate ECR	Alabama Power’s rate energy cost recovery
Rate NDR	Alabama Power’s natural disaster reserve rate
Rate RSE	Alabama Power’s rate stabilization and equalization plan
ROE	Return on equity
S&P	Standard and Poor’s Rating Services, a division of The McGraw Hill Companies, Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company

  SOUTHERN COMPANYD-3

DEFINITIONS (continued)

Term	Meaning
SMEPA	South Mississippi Electric Power Association
Southern Company system	The Southern Company, the traditional operating companies, Southern Power, SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless, and other subsidiaries
SouthernLINC Wireless	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power

D-4  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company and Subsidiary Companies 2014 Annual Report

OVERVIEW

Business Activities

The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the Southern Company system, which consists of the traditional operating companies, Southern Power, and other direct and indirect subsidiaries. The primary business of the Southern Company system is electricity sales by the traditional operating companies 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, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Many factors affect the opportunities, challenges, and risks of the Southern Company system’s electricity business. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, including new plants, and restoration following major storms. Subsidiaries of Southern Company are constructing Plant Vogtle Units 3 and 4 and the Kemper IGCC. Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4, each with approximately 1,100 MWs, and Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW Kemper IGCC.

Each of the traditional operating companies has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 3 to the financial statements under “Retail Regulatory Matters” and “Integrated Coal Gasification Combined Cycle” for additional information.

Another major factor is the profitability of the competitive market-based wholesale generating business. Southern Power’s strategy is to acquire, construct, and sell power plants, including renewable energy projects, and to enter into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives.

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

Key Performance Indicators

In striving to achieve superior risk-adjusted returns while providing cost-effective energy to more than four million customers, the Southern Company system continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share (EPS). Southern Company’s financial success is directly tied to customer satisfaction. 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 results of the Southern Company system.

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 Southern Company system’s fossil/hydro 2014 Peak Season EFOR was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance. The Southern Company system’s performance for 2014 was better than the target for these reliability measures. Primarily as a result of charges for estimated probable losses related to construction of the Kemper IGCC, Southern Company’s EPS for 2014 did not meet the target on a GAAP basis. See RESULTS OF OPERATIONS – “Estimated Loss on Kemper IGCC” and Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

Excluding the charges for estimated probable losses related to construction of the Kemper IGCC and the 2015 Mississippi Supreme Court decision, Southern Company’s 2014 results compared with its targets for some of these key indicators are reflected in the following chart:

Key Performance Indicator	2014 Target Performance	2014 Actual Performance
System Customer Satisfaction	Top quartile in customer surveys	Top quartile
Peak Season System EFOR — fossil/hydro	5.51% or less	1.93%
Basic EPS — As Reported	$2.72-$2.80	$2.19
Kemper IGCC Impacts		$0.61
EPS, excluding items*		$2.80

* Does not reflect EPS as calculated in accordance with GAAP. The non-GAAP measure of EPS, excluding estimated probable losses relating to Mississippi Power’s construction of the Kemper IGCC and the 2015 Mississippi Supreme Court decision, is calculated by excluding from EPS, as

  SOUTHERN COMPANYD-5

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

determined in accordance with GAAP, the following items: (1) estimated probable losses of $536 million after-tax, or $0.59 per share, relating to Mississippi Power’s construction of the Kemper IGCC and (2) an aggregate of $17 million after-tax, or $0.02 per share, relating to the reversal of previously recognized revenues recorded in 2014 and 2013 and the recognition of carrying costs associated with the 2015 Mississippi Supreme Court decision which reversed the Mississippi PSC’s March 2013 rate order related to the Kemper IGCC. The estimated probable losses relating to the construction of the Kemper IGCC significantly impacted the presentation of EPS in the table above, and any similar charges are items that may occur with uncertain frequency in the future. In addition, neither the estimated probable losses relating to the construction of the Kemper IGCC nor the 2015 Mississippi Supreme Court decision were anticipated or incorporated in the assumptions used to develop the EPS target performance for 2014 reflected in the table above. See RESULTS OF OPERATIONS – “Estimated Loss on Kemper IGCC” and Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information on the estimated probable losses relating to the Kemper IGCC and the 2015 Mississippi Supreme Court decision. Southern Company management uses the non-GAAP measure of EPS, excluding these items, to evaluate the performance of Southern Company’s ongoing business activities and its 2014 performance on a basis consistent with the assumptions used in developing the 2014 performance targets and to compare certain results to prior periods. Southern Company believes this presentation is useful to investors by providing additional information for purposes of evaluating the performance of Southern Company’s business activities. This presentation is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance.

Earnings

Southern Company’s net income after dividends on preferred and preference stock of subsidiaries was $2.0 billion in 2014, an increase of $319 million, or 19.4%, from the prior year. The increase was primarily related to an increase in retail revenues due to retail base rate increases, as well as colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013. The increase in net income was also the result of lower pre-tax charges of $868 million ($536 million after tax) recorded in 2014 compared to pre-tax charges of $1.2 billion ($729 million after tax) recorded in 2013 for revisions of estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC. These increases were partially offset by increases in non-fuel operations and maintenance expenses.

Southern Company’s net income after dividends on preferred and preference stock of subsidiaries was $1.6 billion in 2013, a decrease of $706 million, or 30.0%, from the prior year. The decrease was primarily the result of pre-tax charges of $1.2 billion ($729 million after-tax) for revisions of estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC. Also contributing to the decrease in net income were increases in depreciation and amortization and non-fuel operations and maintenance expenses, partially offset by increases in retail revenues and AFUDC.

Basic EPS was $2.19 in 2014, $1.88 in 2013, and $2.70 in 2012. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.18 in 2014, $1.87 in 2013, and $2.67 in 2012. EPS for 2014 was negatively impacted by $0.06 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.0825 in 2014, $2.0125 in 2013, and $1.9425 in 2012. In January 2015, Southern Company declared a quarterly dividend of 52.50 cents per share. This is the 269th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2014, the actual dividend payout ratio was 95%, while the payout ratio of net income excluding estimated probable losses relating to Mississippi Power’s construction of the Kemper IGCC and the 2015 Mississippi Supreme Court decision was 74%.

RESULTS OF OPERATIONS

Discussion of the results of operations is divided into two parts – the Southern Company system’s primary business of electricity sales and its other business activities.

	Amount
	2014			2013			2012
	(in millions)
Electricity business	$	1,969		$	1,652		$	2,321
Other business activities		(6	)		(8	)		29
Net Income	$	1,963		$	1,644		$	2,350

D-6  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

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:

	Amount			Increase (Decrease) from Prior Year
	2014			2014			2013
	(in millions)
Electric operating revenues	$	18,406		$	1,371		$	557
Fuel		6,005			495			453
Purchased power		672			211			(83	)
Other operations and maintenance		4,259			481			83
Depreciation and amortization		1,929			43			114
Taxes other than income taxes		979			47			20
Estimated loss on Kemper IGCC		868			(312	)		1,180
Total electric operating expenses		14,712			965			1,767
Operating income		3,694			406			(1,210	)
Allowance for equity funds used during construction		245			55			47
Interest income		18			—			(4	)
Interest expense, net of amounts capitalized		794			6			(32	)
Other income (expense), net		(73	)		(18	)		2
Income taxes		1,053			118			(465	)
Net income		2,037			319			(668	)
Dividends on preferred and preference stock of subsidiaries		68			2			1
Net income after dividends on preferred and preference stock of subsidiaries	$	1,969		$	317		$	(669	)

Electric Operating Revenues

Electric operating revenues for 2014 were $18.4 billion, reflecting a $1.4 billion increase from 2013. Details of electric operating revenues were as follows:

	Amount
	2014			2013
	(in millions)
Retail — prior year	$	14,541		$	14,187
Estimated change resulting from —
Rates and pricing		300			137
Sales growth (decline)		35			(2	)
Weather		236			(40	)
Fuel and other cost recovery		438			259
Retail — current year		15,550			14,541
Wholesale revenues		2,184			1,855
Other electric operating revenues		672			639
Electric operating revenues	$	18,406		$	17,035
Percent change		8.0	%		3.4	%

Retail revenues increased $1.0 billion, or 6.9%, in 2014 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2014 was primarily due to increased revenues at Georgia Power related to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in the 2013 ARP, and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, as well as higher contributions from market-driven rates from commercial and industrial customers. Also contributing to the increase were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets and increased revenues at Gulf Power primarily resulting from a retail base rate increase and an increase in the environmental cost recovery clause rate, both effective January 2014, as approved by the Florida PSC.

  SOUTHERN COMPANYD-7

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Retail revenues increased $354 million, or 2.5%, in 2013 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2013 was primarily due to base tariff increases at Georgia Power effective April 1, 2012 and January 1, 2013, as approved by the Georgia PSC, related to placing new generating units at Plant McDonough-Atkinson in service and collecting financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, as well as higher contributions from market-driven rates from commercial and industrial customers.

See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters – Alabama Power – Rate CNP,” “– Georgia Power – Rate Plans,” and “– Gulf Power – Retail Base Rate Case” and “Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision” for additional information. Also see “Energy Sales” below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, 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 and short-term opportunity sales. Wholesale revenues from PPAs (other than solar PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system’s generation, demand for energy within the Southern Company system’s service territory, and the availability of the Southern Company system’s generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Wholesale revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system’s variable cost to produce the energy.

Wholesale revenues from power sales were as follows:

	2014		2013		2012
	(in millions)
Capacity and other	$	974	$	971	$	899
Energy		1,210		884		776
Total	$	2,184	$	1,855	$	1,675

In 2014, wholesale revenues increased $329 million, or 17.7%, as compared to the prior year due to a $326 million increase in energy revenues and a $3 million increase in capacity revenues. The increase in energy revenues was primarily related to increased revenue under existing contracts as well as new solar PPAs and requirements contracts primarily at Southern Power, increased demand resulting from colder weather in the first quarter 2014 as compared to the corresponding period in 2013, and an increase in the average cost of natural gas. The increase in capacity revenues was primarily due to wholesale base rate increases at Mississippi Power, partially offset by a decrease in capacity revenues primarily due to lower customer demand and the expiration of certain requirements contracts at Southern Power.

In 2013, wholesale revenues increased $180 million, or 10.7%, as compared to the prior year due to a $108 million increase in energy revenues and a $72 million increase in capacity revenues. The increase in energy revenues was primarily related to an increase in the average price of energy and new solar contracts served by Southern Power’s Plants Campo Verde and Spectrum, which began in 2013, partially offset by a decrease in volume related to milder weather as compared to the prior year. The increase in capacity revenues was primarily due to a new PPA served by Southern Power’s Plant Nacogdoches, which began in June 2012, and an increase in capacity revenues under existing PPAs.

Other Electric Revenues

Other electric revenues increased $33 million, or 5.2%, and $23 million, or 3.7%, in 2014 and 2013, respectively, as compared to the prior years. The 2014 increase was primarily due to increases in open access transmission tariff revenues and transmission service revenues primarily at Alabama Power and Georgia Power, an increase in co-generation steam revenues at Alabama Power, increases in outdoor lighting and solar application fee revenues at Georgia Power, as well as an increase in franchise fees at Gulf Power. The 2013 increase in other electric revenues was primarily a result of increases in transmission revenues related to the open access transmission tariff and rents from electric property related to pole attachments.

D-8  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2014 and the percent change from the prior year were as follows:

	Total KWHs		Total KWH Percent Change						Weather-Adjusted Percent Change
	2014		2014			2013			2014			2013*
	(in billions)
Residential		53.4		5.5	%		0.2	%		—	%		(0.3	)%
Commercial		53.2		1.3			(0.9	)		(0.4	)		(0.1	)
Industrial		54.1		3.3			1.5			3.3			1.5
Other		0.9		0.9			(1.8	)		0.7			(1.9	)
Total retail		161.6		3.3			0.3			0.9	%		0.4	%
Wholesale		32.8		21.7			(2.2	)
Total energy sales		194.4		6.0	%		(0.1	)%

* In the first quarter 2012, Georgia Power began using new actual advanced meter data to compute unbilled revenues. The weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of Georgia Power’s unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, 2013 weather-adjusted residential KWH sales decreased 0.5% as compared to 2012 while 2013 weather-adjusted commercial KWH sales increased 0.2% as compared to 2012.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 5.2 billion KWHs in 2014 as compared to the prior year. This increase was primarily the result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and customer growth, partially offset by a decrease in customer usage. The increase in industrial KWH energy sales was primarily due to increased sales in the primary metals, chemicals, paper, non-manufacturing, transportation, and stone, clay, and glass sectors. Weather-adjusted commercial KWH energy sales decreased primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH energy sales were flat compared to the prior year as a result of customer growth offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, was flat in 2014.

Retail energy sales increased 403 million KWHs in 2013 as compared to the prior year. This increase was primarily the result of customer growth, partially offset by milder weather and a decrease in customer usage. Weather-adjusted residential and commercial energy sales remained relatively flat compared to the prior year with a decrease in customer usage, offset by customer growth. The increase in industrial energy sales was primarily due to increased demand in the paper, primary metals, and stone, clay, and glass sectors.

Wholesale energy sales increased 5.8 billion KWHs in 2014 as compared to the prior year. The increase was primarily related to higher natural gas prices and increased energy sales as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013. Wholesale energy sales decreased 619 million KWHs in 2013 as compared to the prior year. The decrease was primarily related to lower customer demand resulting from milder weather as compared to the prior year.

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.

  SOUTHERN COMPANYD-9

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Details of the Southern Company system’s generation and purchased power were as follows:

	2014		2013		2012
Total generation (billions of KWHs)		191		179		175
Total purchased power (billions of KWHs)		12		12		16
Sources of generation (percent) —
Coal		42		39		38
Nuclear		16		17		18
Gas		39		40		42
Hydro		3		4		2
Cost of fuel, generated (cents per net KWH) —
Coal		3.81		4.01		3.96
Nuclear		0.87		0.87		0.83
Gas		3.63		3.29		2.86
Average cost of fuel, generated (cents per net KWH)		3.25		3.17		2.93
Average cost of purchased power (cents per net KWH)*		7.13		5.27		4.45

* Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

In 2014, total fuel and purchased power expenses were $6.7 billion, an increase of $706 million, or 11.8%, as compared to the prior year. The increase was primarily the result of a $422 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and a $286 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.

In 2013, total fuel and purchased power expenses were $6.0 billion, an increase of $370 million, or 6.6%, as compared to the prior year. This increase was primarily the result of a $446 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $113 million increase in the volume of KWHs generated, partially offset by a $189 million decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy.

Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – “Retail Regulatory Matters – Retail Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

Fuel

In 2014, fuel expense was $6.0 billion, an increase of $495 million, or 9.0%, as compared to the prior year. The increase was primarily due to a 12.7% increase in the volume of KWHs generated by coal, a 10.3% increase in the average cost of natural gas per KWH generated, and a 30.7% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall, partially offset by a 5.0% decrease in the average cost of coal per KWH generated.

In 2013, fuel expense was $5.5 billion, an increase of $453 million, or 9.0%, as compared to the prior year. The increase was primarily due to a 15.0% increase in the average cost of natural gas per KWH generated, partially offset by a 125.9% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

Purchased Power

In 2014, purchased power expense was $672 million, an increase of $211 million, or 45.8%, as compared to the prior year. The increase was primarily due to a 35.3% increase in the average cost per KWH purchased.

In 2013, purchased power expense was $461 million, a decrease of $83 million, or 15.3%, as compared to the prior year. The decrease was primarily due to a 25.9% decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy, partially offset by an 18.4% increase in the average cost per KWH purchased.

Energy purchases will vary depending on demand for energy within the Southern Company system’s service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system’s generation, and the availability of the Southern Company system’s generation.

D-10  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $481 million, or 12.7%, in 2014 as compared to the prior year. The increase was primarily related to increases of $149 million in scheduled outage costs at generation facilities, $103 million in other generation expenses primarily related to commodity and labor costs, $103 million in transmission and distribution costs primarily related to overhead line maintenance, $42 million in net employee compensation and benefits including pension costs, and $31 million in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs.

Other operations and maintenance expenses increased $83 million, or 2.2%, in 2013 as compared to the prior year. Other operations and maintenance expenses in 2013 were significantly below normal levels as a result of cost containment efforts undertaken primarily at Georgia Power to offset the impact of significantly milder than normal weather conditions. Administrative and general expenses increased $63 million primarily as a result of an increase in pension costs. Transmission and distribution expenses increased $27 million primarily due to increases at Georgia Power in transmission system load expense resulting from billing adjustments with integrated transmission system owners.

Production expenses and transmission and distribution expenses fluctuate from year to year due to variations in outage and maintenance schedules and normal changes in the cost of labor and materials.

Depreciation and Amortization

Depreciation and amortization increased $43 million, or 2.3%, in 2014 as compared to the prior year primarily due to increases in depreciation rates related to environmental assets and the amortization of certain regulatory assets at Alabama Power and the completion of the amortization of certain regulatory liabilities at Georgia Power. Also contributing to the increase were increases at Southern Power in plant in service related to the addition of solar facilities in 2013 and 2014, an increase related to equipment retirements resulting from accelerated outage work, and additional component depreciation as a result of increased production. These increases were largely offset by the amortization of $120 million of the regulatory liability for other cost of removal obligations at Alabama Power. See Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Rate CNP” and “– Cost of Removal Accounting Order” for additional information.

Depreciation and amortization increased $114 million, or 6.4%, in 2013 as compared to the prior year primarily due to additional plant in service related to the completion of Georgia Power’s Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, and six Southern Power plants between June 2012 and October 2013, certain coal unit retirement decisions (with respect to the portion of such units dedicated to wholesale service) at Georgia Power, and additional transmission and distribution projects. See FUTURE EARNINGS POTENTIAL – “Retail Regulatory Matters – Georgia Power – Integrated Resource Plans” for additional information on Georgia Power’s unit retirement decisions. These increases were partially offset by a net reduction in amortization primarily related to amortization of a regulatory liability for state income tax credits at Georgia Power and by the deferral of certain expenses under an accounting order at Alabama Power. See Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Compliance and Pension Cost Accounting Order” for additional information on Alabama Power’s accounting order.

See Note 1 to the financial statements under “Regulatory Assets and Liabilities” and “Depreciation and Amortization” for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $47 million, or 5.0%, in 2014 as compared to the prior year primarily due to increases of $34 million in municipal franchise fees related to higher retail revenues in 2014 and $16 million in payroll taxes primarily related to higher employee benefits.

Taxes other than income taxes increased $20 million, or 2.2%, in 2013 as compared to the prior year primarily due to increases in property taxes.

Estimated Loss on Kemper IGCC

In 2014 and 2013, estimated probable losses on the Kemper IGCC of $868 million and $1.2 billion, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). See FUTURE EARNINGS POTENTIAL – “Construction Program” herein and Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

  SOUTHERN COMPANYD-11

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Allowance for Equity Funds Used During Construction

AFUDC equity increased $55 million, or 28.9%, in 2014 as compared to the prior year primarily due to additional capital expenditures at the traditional operating companies, primarily related to environmental and transmission projects, as well as Mississippi Power’s Kemper IGCC.

AFUDC equity increased $47 million, or 32.9%, in 2013 as compared to the prior year primarily due to an increase in CWIP related to Mississippi Power’s Kemper IGCC and increased capital expenditures at Alabama Power, partially offset by the completion of Georgia Power’s Plant McDonough-Atkinson Units 5 and 6 in 2012.

See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $6 million, or 0.8%, in 2014 as compared to the prior year primarily due to a higher amount of outstanding long-term debt and an increase in interest expense resulting from the deposits received by Mississippi Power in January and October 2014 related to SMEPA’s pending purchase of an undivided interest in the Kemper IGCC, partially offset by a decrease in interest expense related to the refinancing of long-term debt at lower rates and an increase in capitalized interest. See Note 6 to the financial statements for additional information.

Interest expense, net of amounts capitalized decreased $32 million, or 3.9%, in 2013 as compared to the prior year primarily due to lower interest rates, the timing of issuances and redemptions of long-term debt, an increase in capitalized interest primarily resulting from AFUDC debt associated with Mississippi Power’s Kemper IGCC, and an increase in capitalized interest associated with the construction of Southern Power’s Plants Campo Verde and Spectrum. These decreases were partially offset by a decrease in capitalized interest resulting from the completion of Southern Power’s Plants Nacogdoches and Cleveland, a reduction in AFUDC debt due to the completion of Georgia Power’s Plant McDonough-Atkinson Units 5 and 6, and the conclusion of certain state and federal tax audits in 2012.

Other Income (Expense), Net

Other income (expense), net decreased $18 million, or 32.7%, in 2014 as compared to the prior year primarily due to an $8 million decrease in wholesale operating fee revenue at Georgia Power and $7 million associated with Mississippi Power’s settlement with the Sierra Club. See Note 3 to the financial statements under “Other Matters – Sierra Club Settlement Agreement” for additional information.

Income Taxes

Income taxes increased $118 million, or 12.6%, in 2014 as compared to the prior year primarily due to higher pre-tax earnings, partially offset by an increase in non-taxable AFUDC equity and an increase in tax benefits related to federal ITCs.

Income taxes decreased $465 million, or 33.2%, in 2013 as compared to the prior year primarily due to lower pre-tax earnings, an increase in tax benefits recognized from ITCs at Southern Power, and a net increase in non-taxable AFUDC equity, partially offset by a decrease in state income tax credits, primarily at Georgia Power.

Other Business Activities

Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in leveraged lease projects, and telecommunications. These businesses are classified in general categories and may comprise one or both of the following subsidiaries: Southern Company Holdings, Inc. (Southern Holdings) invests in various projects, including leveraged lease projects, and 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

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

	Amount			Increase (Decrease) from Prior Year
	2014			2014			2013
	(in millions)
Operating revenues	$	61		$	9		$	(7	)
Other operations and maintenance		95			27			(9	)
Depreciation and amortization		16			1			—
Taxes other than income taxes		2			—			—
Total operating expenses		113			28			(9	)
Operating income (loss)		(52	)		(19	)		2
Interest income		1			—			(17	)
Other income (expense), net		10			36			(45	)
Interest expense		41			5			(3	)
Income taxes		(76	)		10			(20	)
Net income (loss)	$	(6	)	$	2		$	(37	)

Operating Revenues

Southern Company’s non-electric operating revenues for these other business activities increased $9 million, or 17.3%, in 2014 as compared to the prior year. The increase was primarily related to higher operating revenues at Southern Holdings, partially offset by decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry. Non-electric operating revenues for these other businesses decreased $7 million, or 11.9%, in 2013 as compared to the prior year. The decrease was primarily the result of decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other business activities increased $27 million, or 39.7%, in 2014 as compared to the prior year. The increase was primarily due to insurance proceeds received in 2013 related to a litigation settlement with MC Asset Recovery, LLC and higher operating expenses at Southern Holdings. Other operations and maintenance expenses for these other business activities decreased $9 million, or 11.7%, in 2013 as compared to the prior year. The decrease was primarily related to lower operating expenses at SouthernLINC Wireless and decreases in consulting and legal fees, partially offset by higher operating expenses at Southern Holdings and a decrease in the amount of insurance proceeds received in 2013 related to a litigation settlement with MC Asset Recovery, LLC as compared to the amount received in 2012. See Note 3 to the financial statements under “Insurance Recovery” for additional information related to the litigation settlement with MC Asset Recovery, LLC.

Interest Income

Interest income for these other business activities decreased $17 million in 2013 as compared to the prior year primarily due to the conclusion of certain federal income tax audits in 2012.

Other Income (Expense), Net

Other income (expense), net for these other business activities increased $36 million in 2014 as compared to the prior year. The increase was primarily due to the restructuring of a leveraged lease investment in the first quarter of 2013 and a decrease in charitable contributions in 2014. Other income (expense), net for these other business activities decreased $45 million in 2013 as compared to the prior year. The decrease was primarily due to the restructuring of a leveraged lease investment and an increase in charitable contributions.

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. See Note 1 under “Leveraged Leases” for additional information.

Interest Expense

Interest expense for these other business activities increased $5 million, or 13.9%, in 2014 as compared to the prior year. The increase was primarily due to a higher amount of outstanding long-term debt, partially offset by the refinancing of long-term debt at lower rates.

  SOUTHERN COMPANYD-13

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Income Taxes

Income taxes for these other business activities increased $10 million, or 11.6%, in 2014 and decreased $20 million, or 30.3%, in 2013 as compared to the prior year primarily as a result of changes in pre-tax earnings (losses).

Effects of Inflation

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

FUTURE EARNINGS POTENTIAL

General

The four traditional operating companies operate as vertically integrated utilities providing electricity to customers within their service areas in the Southeast. 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 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 the Southern Company system’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 timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of the competitive wholesale business and successfully expanding investments in renewable energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power, as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings.

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, and 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 federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under “Environmental Matters” for additional information.

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. An adverse outcome could require substantial capital expenditures that cannot be determined at this

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

time and could possibly require payment of substantial penalties. See Note 3 to the financial statements under “Environmental Matters – New Source Review Actions” for additional information. The ultimate outcome of these matters cannot be determined at this time.

Environmental Statutes and Regulations

General

The electric utilities’ operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2014, the traditional operating companies had invested approximately $10.6 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $1.1 billion, $0.7 billion, and $0.3 billion for 2014, 2013, and 2012, respectively. The Southern Company system expects that capital expenditures to comply with environmental statutes and regulations will total approximately $2.1 billion from 2015 through 2017, with annual totals of approximately $1.0 billion, $0.5 billion, and $0.6 billion for 2015, 2016, and 2017, respectively. These estimated expenditures do not include any potential compliance costs that may arise from the EPA’s proposed rules that would limit CO₂ emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See “Global Climate Issues” for additional information.

The Southern Company system’s ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and regulations relating to global climate change that are promulgated, including the proposed environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See “Retail Regulatory Matters – Alabama Power – Environmental Accounting Order” and “Retail Regulatory Matters – Georgia Power – Integrated Resource Plans” herein and Note 3 to the financial statements under “Other Matters – Sierra Club Settlement Agreement” for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and Mississippi Power.

Compliance with any new federal or state legislation or regulations relating to air quality, water, CCR, global climate change, or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities’ operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the electric utilities’ commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Southern Company system. Since 1990, the electric utilities have spent approximately $9.5 billion in reducing and monitoring emissions pursuant to the Clean Air Act. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.

In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. Compliance for existing sources is required by April 16, 2015 up to April 16, 2016 for affected units for which extensions have been granted. On November 25, 2014, the U.S. Supreme Court granted a petition for review of the final MATS rule.

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a more stringent eight-hour ozone NAAQS, which it began to implement in 2011. In 2012, the EPA published its final determination of nonattainment areas based on the 2008 eight-hour ozone NAAQS. The only area within the traditional operating companies’ service territory designated as an ozone nonattainment area is a 15-county area within metropolitan Atlanta. On December 17, 2014, the EPA published a proposed rule to further reduce the current eight-hour ozone standard. The EPA is required by federal court order to complete this rulemaking by October 1, 2015. Finalization of a lower eight-hour ozone standard could result in the designation of new ozone nonattainment areas within the traditional operating companies’ service territory.

The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the traditional operating companies’ service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS

  SOUTHERN COMPANYD-15

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

and, with the exception of the Atlanta area, the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. A redesignation request for the Atlanta area is pending with the EPA. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated final designations for the 2012 annual standard on December 18, 2014, and no new nonattainment areas were designated within the traditional operating companies’ service territory. The EPA has, however, deferred designation decisions for certain areas in Alabama, Florida, and Georgia, so future nonattainment designations in these areas are possible.

Final revisions to the NAAQS for sulfur dioxide (SO₂), which established a new one-hour standard, became effective in 2010. No areas within the Southern Company system’s service territory have been designated as nonattainment under this rule. However, the EPA has announced plans to make additional designation decisions for SO₂ in the future, which could result in nonattainment designations for areas within the Southern Company system’s service territory. Implementation of the revised SO₂ standard could require additional reductions in SO₂ emissions and increased compliance and operational costs.

On February 13, 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In March 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA’s latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units owned by Alabama Power, units co-owned with Mississippi Power, and units owned by SEGCO, which is jointly owned by Alabama Power and Georgia Power.

Each of the states in which the Southern Company system has fossil generation is subject to the requirements of the Cross State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO₂ and nitrogen oxide emissions from power plants in 28 states in two phases, with Phase I beginning in 2015 and Phase II beginning in 2017. In 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR in its entirety, but on April 29, 2014, the U.S. Supreme Court overturned that decision and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The U.S. Court of Appeals for the District of Columbia Circuit granted the EPA’s motion to lift the stay of the rule, and the first phase of CSAPR took effect on January 1, 2015.

The EPA finalized the Clean Air Visibility Rule (CAVR) in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter.

In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CTs). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units), during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.

In February 2013, the EPA proposed a rule that would require certain states to revise the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). The EPA proposed to supplement the 2013 proposed rule on September 17, 2014, making it more stringent. The EPA has entered into a settlement agreement requiring it to finalize the proposed rule by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, Mississippi, and North Carolina) to revise their SSM provisions within 18 months after issuance of the final rule.

The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. As part of this strategy, certain of the traditional operating companies have developed a compliance plan for the MATS rule which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO₂ NAAQS, the Alabama opacity rule, CSAPR, CAVR, the MATS rule, the NSPS for CTs, and the SSM rule on the Southern Company system cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

In addition to the federal air quality laws described above, Georgia Power is also subject to the requirements of the 2007 State of Georgia Multi-Pollutant Rule. The Multi-Pollutant Rule, as amended, is designed to reduce emissions of mercury, SO₂, and nitrogen oxide state-wide by requiring the installation of specified control technologies at certain coal-fired generating units by specific dates between December 31, 2008 and April 16, 2015. A companion rule requires a 95% reduction in SO₂ emissions

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

from the controlled units on the same or similar timetable. Through December 31, 2014, Georgia Power had installed the required controls on 14 of its coal-fired generating units with two additional projects to be completed before the unit-specific installation deadlines.

Water Quality

The EPA’s final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective on October 14, 2014. The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.

In June 2013, the EPA published a proposed rule which requested comments on a range of potential regulatory options for addressing revised technology-based limits for certain wastestreams from steam electric power plants and best management practices for CCR surface impoundments. The EPA has entered into a consent decree requiring it to finalize revisions to the steam electric effluent guidelines by September 30, 2015. The ultimate impact of the rule will also depend on the specific technology requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, which would significantly expand the scope of federal jurisdiction under the CWA. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines.

These proposed and final water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.

Coal Combustion Residuals

The traditional operating companies currently manage CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at 22 electric generating plants. In addition to on-site storage, the traditional operating companies also sell a portion of their CCR to third parties for beneficial reuse. Individual states regulate CCR and the states in the Southern Company system’s service territory each have their own regulatory requirements. Each traditional operating company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.

On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not mandate closure of CCR Units, but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the mandated closure of a CCR Unit. Although the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA’s final rule continues to exclude the beneficial use of CCR from regulation.

The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the traditional operating companies’ ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, Southern Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $860 million and ongoing post-closure care of approximately $140 million. Certain of the traditional operating companies have previously recorded asset retirement obligations (ARO) associated with ash ponds of $506 million, or $468 million on a nominal dollar basis, based on existing state requirements. During 2015, the traditional operating companies will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates.

Environmental Remediation

The Southern Company system 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 Southern Company system could incur substantial costs to clean up properties. The traditional operating companies conduct studies to determine the extent of any required cleanup and the Company has recognized in its financial statements the costs to clean up known

  SOUTHERN COMPANYD-17

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

impacted sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs. 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

In 2014, the EPA published three sets of proposed standards that would limit CO₂ emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. On January 8, 2014, the EPA published proposed standards for new units, and, on June 18, 2014, the EPA published proposed standards governing existing units, known as the Clean Power Plan, and separate standards governing CO₂ emissions from modified and reconstructed units. The EPA’s proposed Clean Power Plan establishes guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA’s proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts.

The Southern Company system filed comments on the EPA’s proposed Clean Power Plan on December 1, 2014. These comments addressed legal and technical issues in addition to providing a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA’s compliance scenarios. Costs associated with this proposal could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the proposed Clean Power Plan on the Southern Company system cannot be determined at this time and will depend upon numerous known and unknown factors. Some of the unknown factors include: the structure, timing, and content of the EPA’s final guidelines; individual state implementation of these guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

Over the past several years, the U.S. Congress has also considered many proposals to reduce greenhouse gas emissions, mandate renewable or clean energy, and impose energy efficiency standards. Such proposals are expected to continue to be considered by the U.S. Congress. International climate change negotiations under the United Nations Framework Convention on Climate Change are also continuing.

The EPA’s greenhouse gas reporting rule requires annual reporting of CO₂ equivalent emissions in metric tons for a company’s operational control of facilities. Based on ownership or financial control of facilities, the Southern Company system’s 2013 greenhouse gas emissions were approximately 102 million metric tons of CO₂ equivalent. The preliminary estimate of the Southern Company system’s 2014 greenhouse gas emissions on the same basis is approximately 112 million metric tons of CO₂ equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.

Retail Regulatory Matters

Alabama Power

Alabama Power’s revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power” for additional information regarding Alabama Power’s rate mechanisms and accounting orders.

Rate RSE

Alabama Power’s Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power’s actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.

On December 1, 2014, Alabama Power submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%.

D-18  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Rate CNP

Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015.

Alabama Power has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry’s application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF’s deliberations cannot be determined at this time. If Alabama Power is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded.

Rate CNP Environmental allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. The Rate CNP Environmental increase effective January 1, 2015 is 1.5%, or $75 million annually, based upon projected billings.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement. See “Environmental Matters – Environmental Statutes and Regulations” herein for additional information regarding environmental regulations.

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power’s approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company’s financial statements.

Cost of Removal Accounting Order

In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts, and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and August 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized at December 31, 2014.

The cost of removal accounting order also required Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities, as allowed under the previous orders.

Non-Environmental Federal Mandated Costs Accounting Order

On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015.

On February 17, 2015, Alabama Power filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry

  SOUTHERN COMPANYD-19

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power’s facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Georgia Power’s revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power” for additional information.

Rate Plans

In December 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC in November 2013.

On January 1, 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) ECCR tariff by approximately $25 million; (3) DSM tariffs by approximately $1 million; and (4) MFF tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million.

On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved adjustments to traditional base, ECCR, DSM, and MFF tariffs effective January 1, 2015 as follows:

• Traditional base tariffs by approximately $107 million to cover additional capacity costs;

• ECCR tariff by approximately $23 million;

• DSM tariffs by approximately $3 million; and

• MFF tariff by approximately $3 million to reflect the adjustments above.

The sum of these adjustments resulted in a base revenue increase of approximately $136 million in 2015.

The 2016 base rate increase, which was approved in the 2013 ARP, will be determined through a compliance filing expected to be filed in late 2015, and will be subject to review by the Georgia PSC.

Under the 2013 ARP, Georgia Power’s retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, Georgia Power projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust Georgia Power’s earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on Georgia Power’s request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case. In 2014, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power expects to refund to retail customers approximately $13 million in 2015, subject to review and approval by the Georgia PSC.

Except as provided above, Georgia Power will not file for a general base rate increase while the 2013 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.

Integrated Resource Plans

See “Environmental Matters – Environmental Statutes and Regulations – Air Quality,” “– Water Quality,” “– Coal Combustion Residuals,” and “– Global Climate Issues,” and “Rate Plans” herein for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent limitations guidelines for steam electric power plants, and additional regulations of CCR and CO₂; the State of Georgia’s Multi-Pollutant Rule; and Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations.

In July 2013, the Georgia PSC approved Georgia Power’s latest triennial Integrated Resource Plan (2013 IRP) including Georgia Power’s request to decertify 16 coal- and oil-fired units totaling 2,093 MWs. Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units.

D-20  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the MATS rule. The decertification date of Plant Branch Unit 1 (250 MWs) was extended from December 31, 2013 as specified in the final order in the 2011 Integrated Resource Plan Update (2011 IRP Update) to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) were also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division in September 2013 to allow for necessary transmission system reliability improvements. In July 2013, the Georgia PSC approved the switch to natural gas as the primary fuel for Plant Yates Units 6 and 7. In September 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP Update in order to comply with the State of Georgia’s Multi-Pollutant Rule.

In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to Georgia Power’s next base rate case, which Georgia Power expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.

On July 1, 2014, the Georgia PSC approved Georgia Power’s request to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. Georgia Power expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan to be filed in 2016. Georgia Power plans to continue to operate the unit as needed until the MATS rule becomes effective in April 2015.

The decertification of these units and fuel conversions are not expected to have a material impact on Southern Company’s financial statements; however, the ultimate outcome depends on the Georgia PSC’s order in the 2016 Rate Case and future fuel cases and cannot be determined at this time.

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power’s next fuel case filing until at least June 30, 2015.

See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Retail Regulatory Matters – Alabama Power – Rate ECR” and “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” for additional information.

Construction Program

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. The construction programs of the traditional operating companies and Southern Power are currently estimated to include an investment of approximately $6.7 billion, $5.4 billion, and $4.3 billion for 2015, 2016, and 2017, respectively.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 and the Kemper IGCC. Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4, each with approximately 1,100 MWs, and Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW Kemper IGCC. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” for additional information.

From 2013 through December 31, 2014, the Company recorded pre-tax charges totaling $2.05 billion ($1.26 billion after-tax) for revisions of estimated costs expected to be incurred on Mississippi Power’s construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company’s statements of income and these changes could be material.

  SOUTHERN COMPANYD-21

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

On January 29, 2015, Georgia Power announced that it was notified by the consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (collectively, Contractor) of the Contractor’s revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

While Georgia Power has not agreed to any change to the guaranteed substantial completion dates (April 2016 for Unit 3 and April 2017 for Unit 4) included in the engineering, procurement, and construction agreement relating to Plant Vogtle Units 3 and 4, Georgia Power’s twelfth Vogtle Construction Monitoring (VCM) report, filed February 27, 2015, includes a requested amendment to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor’s revised forecast, to include the estimated owner’s costs associated with the proposed 18-month Contractor delay, and to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $5.0 billion. No Contractor costs related to the Contractor’s proposed 18-month delay are included in the twelfth VCM report. The twelfth VCM report estimates total associated financing costs during the construction period to be approximately $2.5 billion.

Additionally, there are certain risks associated with the construction program in general and certain risks associated with the licensing, construction, and operation of nuclear generating units in particular, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” for additional information.

Income Tax Matters

See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information about the Kemper IGCC. The ultimate outcome of these tax matters cannot be determined at this time.

Bonus Depreciation

On December 19, 2014, the Tax Increase Prevention Act of 2014 (TIPA) was signed into law. The TIPA retroactively extended several tax credits through 2014 and extended 50% bonus depreciation for property placed in service in 2014 (and for certain long-term production-period projects to be placed in service in 2015). The extension of 50% bonus depreciation will have a positive impact on Southern Company’s cash flows and, combined with bonus depreciation allowed under the American Taxpayer Relief Act of 2012 (ATRA), will result in approximately $630 million of positive cash flows. Additionally, the estimated cash flow benefit impact of bonus depreciation for long-term production-period projects to be placed in service in 2015 related to TIPA is expected to be approximately $220 million to $240 million for the 2015 tax year.

Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code of 1986, as amended (Internal Revenue Code) Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through December 31, 2014, Southern Company had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $210 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA’s proposed purchase of an undivided interest in the Kemper IGCC.

In 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA included renewable energy incentives. In January 2013, the ATRA was signed into law. The ATRA retroactively extended several renewable energy incentives through 2013, including extending federal ITCs for biomass projects which began construction before January 1, 2014. The current law provides for a 30% federal ITC for solar facilities placed in service through 2016 and, unless extended, will adjust to 10% for solar facilities placed in service thereafter. The Company has received ITCs in connection with Southern Power’s investments in solar and biomass facilities. See Note 1 to the financial statements under “Income and Other Taxes” for additional information regarding credits amortized and the tax benefit related to basis differences in 2014, 2013, and 2012.

Additionally, the TIPA extended the production tax credit for wind and certain other renewable sources of electricity to facilities for which construction had commenced by the end of 2014.

Section 174 Research and Experimental Deduction

Southern Company reduced tax payments for 2014 and included in its 2013 consolidated federal income tax return deductions for research and experimental expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $160 million as of December 31, 2014. See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information.

D-22  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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 or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with GAAP. 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 reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company’s Board of Directors.

Electric Utility Regulation

Southern Company’s traditional operating companies, which comprised approximately 94% of Southern Company’s total operating revenues for 2014, 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, including a reasonable return on equity. As a result, the traditional operating companies apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations and financial condition 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 any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. 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 is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and, in accordance with GAAP, records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial position, results of operations, or cash flows.

Pension and Other Postretirement Benefits

Southern Company’s calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets,

  SOUTHERN COMPANYD-23

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

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

Key elements in determining Southern Company’s pension and other postretirement benefit expense in accordance with GAAP are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on postretirement benefit plan assets is based on Southern Company’s investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company’s target asset allocation. Southern Company discounts the future cash flows related to its postretirement benefit plans using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company’s pension plans and other postretirement benefit plans by approximately $636 million and $92 million, respectively. The adoption of new mortality tables will increase net periodic costs related to the Company’s pension plans and other postretirement benefit plans in 2015 by $86 million and $10 million, respectively.

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

Change in Assumption	Increase/(Decrease) in Total Benefit Expense for 2015	Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2014	Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2014
	(in millions)
25 basis point change in discount rate	$36/$(34)	$409/$(385)	$64/$(61)
25 basis point change in salaries	$19/$(18)	$103/$(99)	$–/$–
25 basis point change in long-term return on plan assets	$24/$(24)	N/A	N/A

N/A – Not applicable

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

During 2014, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $70.0 million ($43.2 million after tax) in the fourth quarter 2014, $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $540.0 million ($333.5 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.05 billion ($1.26 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through December 31, 2014.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s statements of income and these changes could be material. Any further cost increases and/or extensions of the in- service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this

D-24  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power’s revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company’s results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information.

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings in 2014 and 2013 were negatively affected by revisions to the cost estimate for the Kemper IGCC; however, Southern Company’s financial condition remained stable at December 31, 2014 and December 31, 2013. Through December 31, 2014, Southern Company has incurred non-recoverable cash expenditures of $1.3 billion and is expected to incur approximately $702 million in additional non-recoverable cash expenditures through completion of the Kemper IGCC. Southern Company’s cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system’s capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to comply with environmental regulations, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system’s cash needs. For the three-year period from 2015 through 2017, Southern Company’s projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Southern Company system’s projected capital expenditures in that period include investments to build new generation facilities, to maintain existing generation facilities, to add environmental equipment for existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. 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. See “Sources of Capital,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Southern Company’s investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of December 31, 2014 as compared to December 31, 2013. In December 2014, certain of the traditional operating companies and other subsidiaries voluntarily contributed an aggregate of $500 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. See “Contractual Obligations” herein and Notes 1 and 2 to the financial statements under “Nuclear Decommissioning” and “Pension Plans,” respectively, for additional information.

Net cash provided from operating activities in 2014 totaled $5.8 billion, a decrease of $282 million from 2013. Significant changes in operating cash flow for 2014 as compared to 2013 include $500 million of voluntary contributions to the qualified pension plan and an increase in receivables due to under recovered fuel costs, partially offset by an increase in accrued compensation. Net cash provided from operating activities in 2013 totaled $6.1 billion, an increase of $1.2 billion from 2012. The most significant change in operating cash flow for 2013 as compared to 2012 was a decrease in fossil fuel stock due to an increase in KWH generation.

Net cash used for investing activities in 2014, 2013, and 2012 totaled $6.4 billion, $5.7 billion, and $5.2 billion, respectively. The cash used for investing activities in each of these years was primarily due to gross property additions for installation of equipment to comply with environmental standards, construction of generation, transmission, and distribution facilities, acquisitions of solar facilities, and purchases of nuclear fuel.

  SOUTHERN COMPANYD-25

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Net cash provided from financing activities totaled $644 million in 2014 due to issuances of long-term debt and common stock, partially offset by common stock dividend payments, redemptions of long-term debt, and a reduction in short-term debt. Net cash used for financing activities totaled $324 million in 2013 due to redemptions of long-term debt and payments of common stock dividends, partially offset by issuances of long-term debt and common stock and an increase in notes payable. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes in 2014 included an increase of $3.7 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities and a $1.8 billion increase in other regulatory assets, deferred related to pension and other postretirement benefits. Other significant changes included a $2.9 billion increase in short-term debt primarily related to debt maturing within the next year and borrowings to fund the Southern Company subsidiaries’ continuous construction programs, a $1.2 billion increase in stockholders’ equity, a $1.0 billion increase in accumulated deferred income taxes primarily as a result of bonus depreciation, and a $971 million increase in employee benefit obligations primarily as a result of changes in actuarial assumptions. See Note 2 and Note 5 to the financial statements for additional information regarding retirement benefits and deferred income taxes, respectively.

At the end of 2014, the market price of Southern Company’s common stock was $49.11 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $21.98 per share, representing a market-to-book value ratio of 223%, compared to $41.11, $21.43, and 192%, respectively, at the end of 2013.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flow, short-term debt, term loans, 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 2015, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities and the Southern Company system’s capital requirements.

Except as described herein, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.

On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power’s reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Power’s 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power’s rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. See Note 6 to the financial statements under “DOE Loan Guarantee Borrowings” for additional information regarding the Loan Guarantee Agreement and Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” for additional information regarding Plant Vogtle Units 3 and 4.

Eligible Project Costs incurred through December 31, 2014 would allow for borrowings of up to $2.1 billion under the FFB Credit Facility. Through December 31, 2014, Georgia Power had borrowed $1.2 billion under the FFB Credit Facility, leaving $0.9 billion of currently available borrowing ability.

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for the commercial operation of the Kemper IGCC. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

The issuance of securities by the traditional operating companies is generally subject to the approval of the applicable state PSC. The issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the 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 securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

D-26  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

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 in the Southern Company system.

As of December 31, 2014, Southern Company’s current liabilities exceeded current assets by $2.6 billion, primarily due to long-term debt of the traditional operating companies and Southern Power that is due within one year of $3.3 billion. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets and financial institutions.

At December 31, 2014, Southern Company and its subsidiaries had approximately $710 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2014 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company	2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
									(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power		228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power		80		165		30		—		275		275		50		—		50		30
Mississippi Power		135		165		—		—		300		300		25		40		65		70
Southern Power		—		—		—		500		500		488		—		—		—		—
Other		70		—		—		—		70		70		20		—		20		50
Total	$	513	$	530	$	30	$	4,130	$	5,203	$	5,177	$	153	$	40	$	193	$	320

See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014 was approximately $1.8 billion. In addition, at December 31, 2014, the traditional operating companies had $476 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. As of December 31, 2014, $98 million of certain pollution control revenue bonds of Georgia Power were reclassified to securities due within one year in anticipation of their redemption in connection with unit retirement decisions.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew their bank credit arrangements as needed, prior to expiration.

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Southern Company, the traditional operating companies, and Southern Power are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

  SOUTHERN COMPANYD-27

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Details of short-term borrowings were as follows:

	Short-term Debt at the End of the Period				Short-term Debt During the Period  (a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
December 31, 2014:
Commercial paper	$	803		0.3%	$	754		0.2%	$	1,582
Short-term bank debt		—		—%		98		0.8%		400
Total	$	803		0.3%	$	852		0.3%
December 31, 2013:
Commercial paper	$	1,082		0.2%	$	993		0.3%	$	1,616
Short-term bank debt		400		0.9%		107		0.9%		400
Total	$	1,482		0.4%	$	1,100		0.3%
December 31, 2012:
Commercial paper	$	820		0.3%	$	550		0.3%	$	938
Short-term bank debt		—		—%		116		1.2%		300
Total	$	820		0.3%	$	666		0.5%

(a) Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2014, 2013, and 2012.

The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes, and cash from operations.

Financing Activities

During 2014, Southern Company issued approximately 20.8 million shares of common stock (including approximately 5.0 million treasury shares) for approximately $806 million through the employee and director stock plans and the Southern Investment Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators.

From August 2013 through December 2014, Southern Company used shares held in treasury, to the extent available, and newly issued shares to satisfy the requirements under the Southern Investment Plan and the employee savings plan. Beginning in January 2015, Southern Company ceased issuing additional shares under the Southern Investment Plan and the employee savings plan. All sales under these plans are now being funded with shares acquired on the open market by the independent plan administrators.

Beginning in 2015, Southern Company expects to repurchase shares of common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises. The Southern Company Board of Directors has approved the repurchase of up to 20 million shares of common stock for such purpose until December 31, 2017. Repurchases may be made by means of open market purchases, privately negotiated transactions, or accelerated or other share repurchase programs, in accordance with applicable securities laws.

D-28  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2014:

Company	Senior Note Issuances		Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(a)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(b) and Maturities
	(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—
Alabama Power		400		—		254		254		—			—
Georgia Power		—		—		40		37		1,200			5
Gulf Power		200		75		42		29		—			—
Mississippi Power		—		—		—		—		493			256
Southern Power		—		—		—		—		10			10
Other		—		—		—		—		—			19
Elimination(c)		—		—		—		—		(220	)		(220	)
Total	$	1,350	$	425	$	336	$	320	$	1,483		$	70

(a) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013 and remarketing by Georgia Power of $40 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.

(b) Includes reductions in capital lease obligations resulting from cash payments under capital leases.

(c) Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company’s Consolidated Financial Statements. This loan was repaid on September 29, 2014.

In May 2014, Southern Company’s $350 million aggregate principal amount of its Series 2009A 4.15% Senior Notes due May 15, 2014 matured.

In August 2014, Southern Company issued $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes due August 15, 2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019. The proceeds were used to pay a portion of Southern Company’s outstanding short-term indebtedness and for other general corporate purposes.

Southern Company’s subsidiaries used the proceeds of the debt issuances shown in the table above for the redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.

In addition to the amounts reflected in the table above, in June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014.

In addition to the amounts reflected in the table above, in January 2014 and October 2014, Mississippi Power received an additional $75 million and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA” for additional information.

Georgia Power’s “Other Long-Term Debt Issuances” reflected in the table above include borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion on February 20, 2014 and $200 million on December 11, 2014. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. The interest rate applicable to the $200 million advance in December 2014 is 3.002% for an interest period that extends to 2044. The final maturity date for all advances under the FFB Credit Facility is February 20, 2044. The proceeds of the borrowings in 2014 under the FFB Credit Facility were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which are being amortized over the life of the borrowings under the FFB Credit Facility.

  SOUTHERN COMPANYD-29

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Under the Loan Guarantee Agreement, Georgia Power is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements under “DOE Loan Guarantee Borrowings” for additional information.

In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.

During 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million.

In October 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $900 million.

In November and December 2014, Georgia Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated borrowings under the FFB Credit Facility in 2015. The notional amount of the swaps totaled $700 million.

Subsequent to December 31, 2014, Alabama Power announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035, which will occur on March 16, 2015.

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.

Credit Rating Risk

Southern Company and its subsidiaries do 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, energy price risk management, interest rate derivatives, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at December 31, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3		435
Below BBB- and/or Baa3		2,305

Subsequent to December 31, 2014, Moody’s affirmed the senior unsecured debt rating of Mississippi Power and revised the ratings outlook for Mississippi Power from stable to negative.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Market Price Risk

The Southern Company system is exposed to market risks, primarily commodity price risk and interest rate risk. The Southern Company system may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, the applicable 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 applicable company’s policies in areas such as counterparty exposure and risk management practices. The Southern Company system’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

D-30  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives outstanding at December 31, 2014 have a notional amount of $2.1 billion and are related to fixed and floating rate obligations. The weighted average interest rate on $3.4 billion of long-term variable interest rate exposure at January 1, 2015 was 0.94%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $34 million at January 1, 2015. See Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements for additional information.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, 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 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, 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. Southern Company had no material change in market risk exposure for the year ended December 31, 2014 when compared to the year ended December 31, 2013.

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:

	2014 Changes			2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(32	)	$	(85	)
Contracts realized or settled:
Swaps realized or settled		(9	)		43
Options realized or settled		6			19
Current period changes(a):
Swaps		(131	)		2
Options		(22	)		(11	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(188	)	$	(32	)

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

The net hedge volumes of energy-related derivative contracts for the years ended December 31 were as follows:

	2014		2013
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps		200		216
Commodity – Natural gas options		44		59
Total hedge volume		244		275

The weighted average swap contract cost above market prices was approximately $0.84 per mmBtu as of December 31, 2014 and $0.10 per mmBtu as of December 31, 2013. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the traditional operating companies’ fuel cost recovery clauses.

At December 31, 2014 and 2013, substantially all of the Southern Company system’s energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company’s fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI 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 and were not material for any year presented.

  SOUTHERN COMPANYD-31

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2014 were as follows:

	Fair Value Measurements December 31, 2014
	Total Fair Value			Maturity
				Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(188	)		(109	)		(76	)		(3)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(188	)	$	(109	)	$	(76	)	$	(3)

Southern Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under “Financial Instruments” and Note 11 to the financial statements.

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

Capital Requirements and Contractual Obligations

The Southern Company system’s construction program is currently estimated to be $6.7 billion for 2015, $5.4 billion for 2016, and $4.3 billion for 2017, which includes expenditures related to the construction and start-up of the Kemper IGCC of $801 million for 2015 and $132 million for 2016. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA’s proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $596 million (including construction costs for all prior periods relating to its proposed ownership interest). Capital expenditures to comply with environmental statutes and regulations included in these estimated amounts are $1.0 billion, $0.5 billion, and $0.6 billion for 2015, 2016, and 2017, respectively. The Southern Company system’s amounts include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. These estimated expenditures do not include any potential compliance costs that may arise from the EPA’s proposed rules that would limit CO₂ emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” for additional information.

See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. See Note 3 to the financial statements under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” for information regarding additional factors that may impact construction expenditures.

In addition, the construction program includes the development and construction of new generating facilities with designs that have not been finalized or previously constructed, including first-of-a-kind technology, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development and construction of new facilities is subject to a number of factors, including, but not limited to, labor costs and productivity, adverse weather conditions,

D-32  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC).

As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.”

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

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information.

Contractual Obligations

	2015		2016- 2017		2018- 2019		After 2019		Total
	(in millions)
Long-term debt(a) —
Principal	$	3,302	$	3,345	$	2,050	$	15,282	$	23,979
Interest		857		1,563		1,355		11,379		15,154
Preferred and preference stock dividends(b)		68		136		136		—		340
Financial derivative obligations(c)		138		76		3		—		217
Operating leases(d)		100		154		73		248		575
Capital leases(d)		31		25		22		81		159
Unrecognized tax benefits(e)		170		—		—		—		170
Purchase commitments —
Capital(f)		6,222		8,899		—		—		15,121
Fuel(g)		4,012		5,155		3,321		9,869		22,357
Purchased power(h)		327		738		761		3,892		5,718
Other(i)		233		476		378		1,369		2,456
Trusts —
Nuclear decommissioning(j)		5		11		11		110		137
Pension and other postretirement benefit plans(k)		112		224		—		—		336
Total	$	15,577	$	20,802	$	8,110	$	42,230	$	86,719

(a) All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue, when economically feasible, 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, 2015, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).

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

(c) Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.

(d) Excludes PPAs that are accounted for as leases and included in purchased power.

(e) See Note 5 to the financial statements under “Unrecognized Tax Benefits” for additional information.

(f) The Southern Company system provides estimated capital expenditures for a three-year period, including capital expenditures and compliance costs associated with environmental regulations. Estimates related to the construction and start-up of the Kemper IGCC exclude SMEPA’s proposed acquisition of a 15% ownership share of the Kemper IGCC. See Note 3 to the financial statements under “Integrated Coal Gasification Combined Cycle” for additional information. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected separately. At December 31, 2014, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations” herein for additional information.

  SOUTHERN COMPANYD-33

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

(g) Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2014.

(h) Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. A total of $1.1 billion of biomass PPAs is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – “Retail Regulatory Matters – Georgia Power – Renewables Development” for additional information.

(i) Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.

(j) Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under “Nuclear Decommissioning” for additional information.

(k) The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company’s subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company’s subsidiaries.

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2014 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, impact of the TIPA, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and 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 changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, CCR, and emissions of sulfur, nitrogen, CO₂, soot, particulate matter, hazardous air pollutants, including mercury, 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 pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax audits;

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

• variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

• available sources and costs of fuels;

• effects of inflation;

• the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

• the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any operational and environmental performance standards, including any PSC requirements and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

D-34  SOUTHERN COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

• investment performance of Southern Company’s employee and retiree benefit plans and the Southern Company system’s nuclear decommissioning trust funds;

• advances in technology;

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

• legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of a rate recovery plan, including the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, and satisfaction of requirements to utilize ITCs and grants;

• Mississippi PSC review of the prudence of Kemper IGCC costs;

• the ultimate outcome and impact of the February 2015 decision of the Mississippi Supreme Court and any further legal or regulatory proceedings regarding any settlement agreement between Mississippi Power and the Mississippi PSC, the March 2013 rate order regarding retail rate increases, or the Baseload Act;

• the ability to successfully operate the electric utilities’ generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

• the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, or financial risks;

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

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

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

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

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

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

• interest rate fluctuations and financial market conditions and the results of financing efforts;

• changes in Southern Company’s or any of its subsidiaries’ credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

• the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

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

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

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

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

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

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

  SOUTHERN COMPANYD-35

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2014, 2013, and 2012

Southern Company and Subsidiary Companies 2014 Annual Report

	2014			2013			2012
	(in millions)
Operating Revenues:
Retail revenues	$	15,550		$	14,541		$	14,187
Wholesale revenues		2,184			1,855			1,675
Other electric revenues		672			639			616
Other revenues		61			52			59
Total operating revenues		18,467			17,087			16,537
Operating Expenses:
Fuel		6,005			5,510			5,057
Purchased power		672			461			544
Other operations and maintenance		4,354			3,846			3,772
Depreciation and amortization		1,945			1,901			1,787
Taxes other than income taxes		981			934			914
Estimated loss on Kemper IGCC		868			1,180			—
Total operating expenses		14,825			13,832			12,074
Operating Income		3,642			3,255			4,463
Other Income and (Expense):
Allowance for equity funds used during construction		245			190			143
Interest income		19			19			40
Interest expense, net of amounts capitalized		(835	)		(824	)		(859	)
Other income (expense), net		(63	)		(81	)		(38	)
Total other income and (expense)		(634	)		(696	)		(714	)
Earnings Before Income Taxes		3,008			2,559			3,749
Income taxes		977			849			1,334
Consolidated Net Income		2,031			1,710			2,415
Dividends on Preferred and Preference Stock of Subsidiaries		68			66			65
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	1,963		$	1,644		$	2,350
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	2.19		$	1.88		$	2.70
Diluted EPS		2.18			1.87			2.67
Average number of shares of common stock outstanding — (in millions)
Basic		897			877			871
Diluted		901			881			879

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

D-36  SOUTHERN COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2014, 2013, and 2012

Southern Company and Subsidiary Companies 2014 Annual Report

	2014			2013			2012
	(in millions)
Consolidated Net Income	$	2,031		$	1,710		$	2,415
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $(6), $-, and $(7), respectively		(10	)		—			(12	)
Reclassification adjustment for amounts included in net income, net of tax of $3, $5, and $7, respectively		5			9			11
Marketable securities:
Change in fair value, net of tax of $-, $(2), and $-, respectively		—			(3	)		—
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(32), $22, and $(2), respectively		(51	)		36			(3	)
Reclassification adjustment for amounts included in net income, net of tax of $2, $4, and $(4), respectively		3			6			(8	)
Total other comprehensive income (loss)		(53	)		48			(12	)
Dividends on preferred and preference stock of subsidiaries		(68	)		(66	)		(65	)
Consolidated Comprehensive Income	$	1,910		$	1,692		$	2,338

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

  SOUTHERN COMPANYD-37

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2014, 2013, and 2012

Southern Company and Subsidiary Companies 2014 Annual Report

	2014			2013			2012
	(in millions)
Operating Activities:
Consolidated net income	$	2,031		$	1,710		$	2,415
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		2,293			2,298			2,145
Deferred income taxes		709			496			1,096
Investment tax credits		35			302			128
Allowance for equity funds used during construction		(245	)		(190	)		(143	)
Pension, postretirement, and other employee benefits		(515	)		131			(398	)
Stock based compensation expense		63			59			55
Estimated loss on Kemper IGCC		868			1,180			—
Other, net		(38	)		(41	)		51
Changes in certain current assets and liabilities —
-Receivables		(352	)		(153	)		234
-Fossil fuel stock		408			481			(452	)
-Materials and supplies		(67	)		36			(97	)
-Other current assets		(57	)		(11	)		(37	)
-Accounts payable		267			72			(89	)
-Accrued taxes		(105	)		(85	)		(71	)
-Accrued compensation		255			(138	)		(28	)
-Mirror CWIP		180			—			—
-Other current liabilities		85			(50	)		89
Net cash provided from operating activities		5,815			6,097			4,898
Investing Activities:
Property additions		(5,977	)		(5,463	)		(4,809	)
Investment in restricted cash		(11	)		(149	)		(280	)
Distribution of restricted cash		57			96			284
Nuclear decommissioning trust fund purchases		(916	)		(986	)		(1,046	)
Nuclear decommissioning trust fund sales		914			984			1,043
Cost of removal, net of salvage		(170	)		(131	)		(149	)
Change in construction payables, net		(107	)		(126	)		(84	)
Prepaid long-term service agreement		(181	)		(91	)		(146	)
Other investing activities		(17	)		124			19
Net cash used for investing activities		(6,408	)		(5,742	)		(5,168	)
Financing Activities:
Increase (decrease) in notes payable, net		(676	)		662			(30	)
Proceeds —
Long-term debt issuances		3,169			2,938			4,404
Interest-bearing refundable deposit		125			—			150
Preference stock		—			50			—
Common stock issuances		806			695			397
Redemptions and repurchases —
Long-term debt		(816	)		(2,830	)		(3,169	)
Common stock repurchased		(5	)		(20	)		(430	)
Payment of common stock dividends		(1,866	)		(1,762	)		(1,693	)
Payment of dividends on preferred and preference stock of subsidiaries		(68	)		(66	)		(65	)
Other financing activities		(25	)		9			19
Net cash provided from (used for) financing activities		644			(324	)		(417	)
Net Change in Cash and Cash Equivalents		51			31			(687	)
Cash and Cash Equivalents at Beginning of Year		659			628			1,315
Cash and Cash Equivalents at End of Year	$	710		$	659		$	628

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

D-38  SOUTHERN COMPANY

CONSOLIDATED BALANCE SHEETS

At December 31, 2014 and 2013

Southern Company and Subsidiary Companies 2014 Annual Report

Assets	2014			2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	710		$	659
Receivables —
Customer accounts receivable		1,090			1,027
Unbilled revenues		432			448
Under recovered regulatory clause revenues		136			58
Other accounts and notes receivable		307			304
Accumulated provision for uncollectible accounts		(18	)		(18	)
Fossil fuel stock, at average cost		930			1,339
Materials and supplies, at average cost		1,039			959
Vacation pay		177			171
Prepaid expenses		665			278
Deferred income taxes, current		506			143
Other regulatory assets, current		346			207
Other current assets		50			39
Total current assets		6,370			5,614
Property, Plant, and Equipment:
In service		70,013			66,021
Less accumulated depreciation		24,059			23,059
Plant in service, net of depreciation		45,954			42,962
Other utility plant, net		211			240
Nuclear fuel, at amortized cost		911			855
Construction work in progress		7,792			7,151
Total property, plant, and equipment		54,868			51,208
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,546			1,465
Leveraged leases		743			665
Miscellaneous property and investments		203			218
Total other property and investments		2,492			2,348
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,510			1,436
Prepaid pension costs		—			419
Unamortized debt issuance expense		202			139
Unamortized loss on reacquired debt		243			269
Other regulatory assets, deferred		4,334			2,495
Other deferred charges and assets		904			618
Total deferred charges and other assets		7,193			5,376
Total Assets	$	70,923		$	64,546

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

  SOUTHERN COMPANYD-39

CONSOLIDATED BALANCE SHEETS

At December 31, 2014 and 2013

Southern Company and Subsidiary Companies 2014 Annual Report

Liabilities and Stockholders’ Equity	2014		2013
	(in millions)
Current Liabilities:
Securities due within one year	$	3,333	$	469
Interest-bearing refundable deposit		275		150
Notes payable		803		1,482
Accounts payable		1,593		1,376
Customer deposits		390		380
Accrued taxes —
Accrued income taxes		151		13
Other accrued taxes		487		456
Accrued interest		295		251
Accrued vacation pay		223		217
Accrued compensation		576		303
Other regulatory liabilities, current		26		82
Mirror CWIP		271		—
Other current liabilities		544		346
Total current liabilities		8,967		5,525
Long-Term Debt (See accompanying statements)		20,841		21,344
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		11,568		10,563
Deferred credits related to income taxes		192		203
Accumulated deferred investment tax credits		1,208		966
Employee benefit obligations		2,432		1,461
Asset retirement obligations		2,168		2,006
Other cost of removal obligations		1,215		1,275
Other regulatory liabilities, deferred		398		479
Other deferred credits and liabilities		594		585
Total deferred credits and other liabilities		19,775		17,538
Total Liabilities		49,583		44,407
Redeemable Preferred Stock of Subsidiaries (See accompanying statements)		375		375
Redeemable Noncontrolling Interest (See accompanying statements)		39		—
Total Stockholders’ Equity (See accompanying statements)		20,926		19,764
Total Liabilities and Stockholders’ Equity	$	70,923	$	64,546
Commitments and Contingent Matters (See notes)

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

D-40  SOUTHERN COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2014 and 2013

Southern Company and Subsidiary Companies 2014 Annual Report

		2014			2013			2014			2013
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate (3.36% at 1/1/15) due 2042		$	206		$	206
Total long-term debt payable to affiliated trusts			206			206
Long-term senior notes and debt —
Maturity	Interest Rates
2014	3.25% to 4.90%		—			428
2015	0.55% to 5.25%		2,375			2,375
2016	1.95% to 5.30%		1,360			1,360
2017	1.30% to 5.90%		1,495			1,095
2018	2.20% to 5.40%		850			850
2019	2.15% to 5.55%		1,175			825
2020 through 2051	1.63% to 6.38%		10,574			9,973
Variable rate (1.29% at 1/1/14) due 2014			—			11
Variable rates (0.77% to 1.17% at 1/1/15) due 2015			775			525
Variable rates (0.56% to 0.63% at 1/1/15) due 2016			450			450
Total long-term senior notes and debt			19,054			17,892
Other long-term debt —
Pollution control revenue bonds —
Maturity	Interest Rates
2019	4.55%		25			25
2022 through 2049	0.28% to 6.00%		1,466			1,453
Variable rates (0.03% to 0.04% at 1/1/15) due 2015			152			54
Variable rate (0.04% at 1/1/15) due 2016			4			4
Variable rate (0.04% to 0.06% at 1/1/15) due 2017			36			36
Variable rate (0.04% at 1/1/14) due 2018			—			19
Variable rates (0.01% to 0.09% at 1/1/15) due 2020 to 2052			1,566			1,642
Plant Daniel revenue bonds (7.13%) due 2021			270			270
FFB loans (3.00% to 3.86%) due 2044			1,200			—
Total other long-term debt			4,719			3,503
Capitalized lease obligations			159			163
Unamortized debt premium			69			79
Unamortized debt discount			(33	)		(30	)
Total long-term debt (annual interest requirement — $857 million)			24,174			21,813
Less amount due within one year			3,333			469
Long-term debt excluding amount due within one year			20,841			21,344			49.4	%		51.5	%
Redeemable Preferred Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 5.44%
Authorized — 20 million shares
Outstanding — 1 million shares			81			81
$1 par value — 5.20% to 5.83%
Authorized — 28 million shares
Outstanding — 12 million shares: $25 stated value			294			294
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $20 million)			375			375			0.9			0.9
Redeemable Noncontrolling Interest			39			—			0.1			—

  SOUTHERN COMPANYD-41

CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)

At December 31, 2014 and 2013

Southern Company and Subsidiary Companies 2014 Annual Report

	2014			2013			2014			2013
	(in millions)						(percent of total)
Common Stockholders’ Equity:
Common stock, par value $5 per share —		4,539			4,461
Authorized — 1.5 billion shares
Issued — 2014: 909 million shares
— 2013: 893 million shares
Treasury — 2014: 0.7 million shares
— 2013: 5.7 million shares
Paid-in capital		5,955			5,362
Treasury, at cost		(26	)		(250	)
Retained earnings		9,609			9,510
Accumulated other comprehensive loss		(128	)		(75	)
Total common stockholders’ equity		19,949			19,008			47.3			45.8
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interest:
Non-cumulative preferred stock
$25 par value — 6.00% to 6.13%
Authorized — 60 million shares
Outstanding — 2 million shares		45			45
Preference stock
Authorized — 65 million shares
Outstanding — $1 par value		343			343
— 5.63% to 6.50% — 14 million shares (non-cumulative)
Outstanding — $100 par or stated value		368			368
— 5.60% to 6.50% — 4 million shares (non-cumulative)
Noncontrolling Interest		221			—
Total preferred and preference stock of subsidiaries and noncontrolling interest (annual dividend requirement — $48 million)		977			756			2.3			1.8
Total stockholders’ equity		20,926			19,764
Total Capitalization	$	42,181		$	41,483			100.0	%		100.0	%

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

D-42  SOUTHERN COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2014, 2013, and 2012

Southern Company and Subsidiary Companies 2014 Annual Report

	Southern Company Common Stockholders’ Equity
	Number of Common Shares					Common Stock							Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries		Noncontrolling Interest			Total
	Issued		Treasury			Par Value		Paid-In Capital		Treasury
	(in thousands)					(in millions)
Balance at December 31, 2011		865,664		(539	)	$	4,328	$	4,410	$	(17	)	$	8,968		$	(111	)	$	707	$	—		$	18,285
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			2,350			—			—		—			2,350
Other comprehensive income (loss)		—		—			—		—		—			—			(12	)		—		—			(12	)
Stock issued		12,139		—			61		336		—			—			—			—		—			397
Stock repurchased, at cost		—		(9,440	)		—		—		(430	)		—			—			—		—			(430	)
Stock-based compensation		—		—			—		106		—			—			—			—		—			106
Cash dividends of $1.9425 per share		—		—			—		—		—			(1,693	)		—			—		—			(1,693	)
Other		—		(56	)		—		3		(3	)		1			—			—		—			1
Balance at December 31, 2012		877,803		(10,035	)		4,389		4,855		(450	)		9,626			(123	)		707		—			19,004
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			1,644			—			—		—			1,644
Other comprehensive income (loss)		—		—			—		—		—			—			48			—		—			48
Stock issued		14,930		4,443			72		441		203			—			—			49		—			765
Stock-based compensation		—		—			—		65		—			—			—			—		—			65
Cash dividends of $2.0125 per share		—		—			—		—		—			(1,762	)		—			—		—			(1,762	)
Other		—		(55	)		—		1		(3	)		2			—			—		—			—
Balance at December 31, 2013		892,733		(5,647	)		4,461		5,362		(250	)		9,510			(75	)		756		—			19,764
Net income after dividends on preferred and preference stock of subsidiaries		—		—			—		—		—			1,963			—			—		—			1,963
Other comprehensive income (loss)		—		—			—		—		—			—			(53	)		—		—			(53	)
Stock issued		15,769		4,996			78		501		227			—			—			—		—			806
Stock-based compensation		—		—			—		86		—			—			—			—		—			86
Cash dividends of $2.0825 per share		—		—			—		—		—			(1,866	)		—			—		—			(1,866	)
Contributions from noncontrolling interest		—		—			—		—		—			—			—			—		221			221
Net income attributable to noncontrolling interest		—		—			—		—		—			—			—			—		(2	)		(2	)
Other		—		(74	)		—		6		(3	)		2			—			—		2			7
Balance at December 31, 2014		908,502		(725	)	$	4,539	$	5,955	$	(26	)	$	9,609		$	(128	)	$	756	$	221		$	20,926

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

  SOUTHERN COMPANYD-43

NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2014 Annual Report

Index to the Notes to Financial Statements

Note		Page
1	Summary of Significant Accounting Polices		D-45
2	Retirement Benefits		D-54
3	Contingencies and Regulatory Matters		D-63
4	Joint Ownership Agreements		D-78
5	Income Taxes		D-79
6	Financing		D-82
7	Commitments		D-87
8	Common Stock		D-88
9	Nuclear Insurance		D-90
10	Fair Value Measurements		D-91
11	Derivatives		D-95
12	Segment and Related Information		D-100
13	Quarterly Financial Information (Unaudited)		D-102

D-44  SOUTHERN COMPANY

NOTES (continued)

Southern Company and Subsidiary Companies 2014 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company’s investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system’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 has an equity investment, but 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 FERC, and the traditional operating companies are also subject to regulation by their respective state PSCs. The companies follow GAAP in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

Regulatory Assets and Liabilities

The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

  SOUTHERN COMPANYD-45

NOTES (continued)

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

	2014			2013			Note
	(in millions)
Retiree benefit plans	$	3,469		$	1,760			(a,p)
Deferred income tax charges		1,458			1,376			(b)
Loss on reacquired debt		267			293			(c)
Fuel-hedging-asset		202			58			(d,p)
Deferred PPA charges		185			180			(e,p)
Vacation pay		177			171			(f,p)
Under recovered regulatory clause revenues		157			70			(g)
Kemper IGCC regulatory assets		148			76			(h)
Asset retirement obligations-asset		119			145			(b,p)
Nuclear outage		99			78			(g)
Property damage reserves-asset		98			37			(i)
Cancelled construction projects		67			70			(j)
Environmental remediation-asset		64			62			(k,p)
Deferred income tax charges — Medicare subsidy		57			65			(l)
Other regulatory assets		195			222			(m)
Other cost of removal obligations		(1,229	)		(1,289	)		(b)
Kemper regulatory liability (Mirror CWIP)		(271	)		(91	)		(h)
Deferred income tax credits		(192	)		(203	)		(b)
Property damage reserves-liability		(181	)		(191	)		(n)
Asset retirement obligations-liability		(130	)		(139	)		(b,p)
Other regulatory liabilities		(95	)		(126	)		(o)
Total regulatory assets (liabilities), net	$	4,664		$	2,624

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

(a) Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

(b) Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the two-year period from January 2015 through December 2016 in accordance with Georgia Power’s 2013 ARP. See Note 3 under “Retail Regulatory Matters – Georgia Power – Rate Plans” for additional information. At December 31, 2014, other cost of removal obligations included $8.4 million recorded as authorized by the Florida PSC in the Settlement Agreement approved in December 2013 (Gulf Power Settlement Agreement).

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

(d) Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

(e) Recovered over the life of the PPA for periods up to nine years.

(f) Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(g) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years.

(h) For additional information, see Note 3 under “Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities.”

(i) Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding eight years.

(j) Costs associated with construction of environmental controls that will not be completed as a result of unit retirements being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022.

(k) Recovered through the environmental cost recovery clause when the remediation is performed.

(l) Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.

(m) Comprised of numerous immaterial components including property taxes, generation site selection/evaluation costs, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4

D-46  SOUTHERN COMPANY

NOTES (continued)

regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding 10 years or, as applicable, over the remaining life of the asset but not beyond 2031.

(n) Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs.

(o) Comprised of numerous immaterial components including over-recovered regulatory clause revenues, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, nuclear disposal fees, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years.

(p) Not earning a return as offset in rate base by a corresponding asset or liability.

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

Revenues

Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. 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.

Southern Company’s electric utility subsidiaries have 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 fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.

Income and Other Taxes

Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies are amortized over the average 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 $22 million in 2014, $16 million in 2013, and $23 million in 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years. Additionally, several subsidiaries have state ITCs, which are recognized in the period in which the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable was not utilized currently and will be carried forward and utilized in future years.

Under the American Recovery and Reinvestment Act of 2009 and the American Taxpayer Relief Act of 2012 (ATRA), certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $11.4 million in 2014, $5.5 million in 2013, and $2.6 million in 2012. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $74 million, $158 million, and $45 million for the years ended December 31, 2014, 2013, and 2012, respectively, which had a material impact on cash flows. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $48 million in 2014, $31 million in 2013, and $8 million in 2012.

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

  SOUTHERN COMPANYD-47

NOTES (continued)

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any 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 cost of equity funds used during construction.

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

	2014		2013
	(in millions)
Generation	$	37,892	$	35,360
Transmission		9,884		9,289
Distribution		17,123		16,499
General		4,198		3,958
Plant acquisition adjustment		123		123
Utility plant in service		69,220		65,229
Information technology equipment and software		244		242
Communications equipment		439		437
Other		110		113
Other plant in service		793		792
Total plant in service	$	70,013	$	66,021

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 other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit’s operating cycle. The refueling cycles for Alabama Power’s Plant Farley and Georgia Power’s Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months, depending on the unit.

Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below:

	Asset Balances at December 31,
	2014			2013
	(in millions)
Office building	$	61		$	61
Nitrogen plant		83			83
Computer-related equipment		60			62
Gas pipeline		6			6
Less: Accumulated amortization		(49	)		(48	)
Balance, net of amortization	$	161		$	164

The amount of non-cash property additions recognized for the years ended December 31, 2014, 2013, and 2012 was $528 million, $411 million, and $524 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2014, 2013, and 2012 was $25 million, $107 million, and $14 million, respectively.

Acquisitions

Southern Power acquires generation assets as part of its overall growth strategy. Southern Power accounts for business acquisitions from non-affiliates as business combinations. Accordingly, Southern Power has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by Southern Power for successful or potential acquisitions have been expensed as incurred.

D-48  SOUTHERN COMPANY

NOTES (continued)

Acquisitions entered into or made by Southern Power during 2014 and 2013 are detailed in the table below:

	MW Capacity		Percentage Ownership	Year of Operation	Party Under PPA Contract for Plant Output	PPA Contract Period	Purchase Price
							(millions)
SG2 Imperial Valley, LLC (a)		150	51%	2014	San Diego Gas & Electric Company	25 years	$	504.7	(c)
Macho Springs Solar LLC (b)		50	90	2014	El Paso Electric Company	20 years	$	130.0	(d)
Adobe Solar, LLC (b)		20	90	2014	Southern California Edison Company	20 years	$	96.2	(d)
Campo Verde Solar, LLC (b)(e)		139	90	2013	San Diego Gas & Electric Company	20 years	$	136.6	(d)

(a) This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc.

(b) This acquisition was made by Southern Power and Turner Renewable Energy, LLC through Southern Turner Renewable Energy, LLC.

(c) Reflects Southern Power’s portion of the purchase price.

(d) Reflects 100% of the purchase price, including Turner Renewable Energy, LLC’s 10% equity contribution.

(e) Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. to complete the construction of the solar facility.

Depreciation and Amortization

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1% in 2014, 3.3% in 2013, and 3.2% in 2012. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $23.5 billion and $22.5 billion at December 31, 2014 and 2013, 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 are 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. Certain of Southern Power’s generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. The book value of plant-in-service as of December 31, 2014 that is depreciated on a units-of-production basis was approximately $470.2 million.

In 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of Georgia Power’s Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), Georgia Power amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $14 million is being amortized annually by Georgia Power over the three years ending December 31, 2016. See Note 3 under “Retail Regulatory Matters – Georgia Power – Rate Plans” for additional information.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years. Accumulated depreciation for other plant in service totaled $533 million and $513 million at December 31, 2014 and 2013, respectively.

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations (ARO) 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. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for AROs primarily relates to the decommissioning of the Southern Company system’s nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Southern Company system has retirement obligations related to various landfill sites, ash ponds, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system’s rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these

  SOUTHERN COMPANYD-49

NOTES (continued)

assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See “Nuclear Decommissioning” herein for additional information on amounts included in rates.

Details of the AROs included in the balance sheets are as follows:

	2014			2013
		(in millions)
Balance at beginning of year	$	2,018		$	1,757
Liabilities incurred		18			6
Liabilities settled		(17	)		(16	)
Accretion		102			97
Cash flow revisions		80			174
Balance at end of year	$	2,201		$	2,018

The cash flow revisions in 2014 are primarily related to Alabama Power’s and SEGCO’s AROs associated with asbestos at their steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on Alabama Power’s updated decommissioning study and Georgia Power’s updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units.

On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the traditional operating companies’ ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, Southern Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $860 million and ongoing post-closure care of approximately $140 million. Certain of the traditional operating companies have previously recorded AROs associated with ash ponds of $506 million, or $468 million on a nominal dollar basis, based on existing state requirements. During 2015, the traditional operating companies will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. Southern Company’s results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates.

Nuclear Decommissioning

The 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 (Funds) to comply with the NRC’s regulations. Use of the Funds is restricted to nuclear decommissioning activities. 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 IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds’ managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds’ managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds’ investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.

Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.

D-50  SOUTHERN COMPANY

NOTES (continued)

The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds’ investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2014 and 2013, approximately $51 million and $32 million, respectively, of the fair market value of the Funds’ securities were on loan and pledged to creditors under the Funds’ managers’ securities lending program. The fair value of the collateral received was approximately $52 million and $33 million at December 31, 2014 and 2013, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.

At December 31, 2014, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $886 million, debt securities of $638 million, and $19 million of other securities. At December 31, 2013, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $896 million, debt securities of $528 million, and $40 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool.

Sales of the securities held in the Funds resulted in cash proceeds of $913 million, $1.0 billion, and $1.0 billion in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $98 million, of which $2 million related to realized gains and $19 million related to unrealized gains and losses related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $181 million, of which $5 million related to realized gains and $119 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds’ expenses, were $137 million, of which $4 million related to realized gains and $75 million related to unrealized gains related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.

For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

At December 31, 2014 and 2013, the accumulated provisions for decommissioning were as follows:

	External Trust Funds				Internal Reserves				Total
	2014		2013		2014		2013		2014		2013
		(in millions)
Plant Farley	$	754	$	713	$	21	$	21	$	775	$	734
Plant Hatch		496		469		—		—		496		469
Plant Vogtle Units 1 and 2		293		277		—		—		293		277

Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2014 based on the most current studies, which were performed in 2013 for Alabama Power’s Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power’s Plant Farley and Georgia Power’s ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:

	Plant Farley		Plant Hatch		Plant Vogtle Units 1 and 2
Decommissioning periods:
Beginning year		2037		2034		2047
Completion year		2076		2068		2072
		(in millions)
Site study costs:
Radiated structures	$	1,362	$	549	$	453
Spent fuel management		—		131		115
Non-radiated structures		80		51		76
Total site study costs	$	1,442	$	731	$	644

  SOUTHERN COMPANYD-51

NOTES (continued)

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 and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power’s annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.

Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with NRC and other applicable requirements.

Allowance for Funds Used During Construction 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, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies’ regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 16.0%, 15.0%, and 8.2% of net income for 2014, 2013, and 2012, respectively.

Cash payments for interest totaled $732 million, $759 million, and $803 million in 2014, 2013, and 2012, respectively, net of amounts capitalized of $111 million, $92 million, and $83 million, respectively.

Impairment of Long-Lived Assets and Intangibles

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

Storm Damage Reserves

Each traditional operating company maintains a reserve to cover or is allowed to defer and recover 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 million in 2014 and $28 million in 2013. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2014 and 2013, there were no such additional accruals. See Note 3 under “Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve” and “Retail Regulatory Matters – Georgia Power – Storm Damage Recovery” for additional information regarding Alabama Power’s NDR and Georgia Power’s deferred storm costs, respectively.

Leveraged Leases

Southern Company has several leveraged lease agreements, with original 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 and international leveraged leases consists of the following at December 31:

		2014			2013
	(in millions)
Net rentals receivable	$	1,495		$	1,440
Unearned income		(752	)		(775	)
Investment in leveraged leases		743			665
Deferred taxes from leveraged leases		(299	)		(287	)
Net investment in leveraged leases	$	444		$	378

D-52  SOUTHERN COMPANY

NOTES (continued)

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

		2014			2013			2012
	(in millions)
Pretax leveraged lease income (loss)	$	24		$	(5)		$	21
Income tax expense		(9	)		2			(8	)
Net leveraged lease income (loss)	$	15		$	(3	)	$	13

Cash and Cash Equivalents

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

Materials and Supplies

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

Fuel Inventory

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

Financial Instruments

Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in “Other” or shown separately as “Risk Management Activities”) and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system’s bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the “normal” scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies’ fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives.

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, 2014, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.

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

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.

Accumulated OCI (loss) balances, net of tax effects, were as follows:

	Qualifying Hedges			Marketable Securities		Pension and Other Postretirement Benefit Plans		Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2013		$        (36	)	$	—	$	(39)	$	(75)
Current period change		(5	)		—		(48)		(53)
Balance at December 31, 2014		$        (41	)	$	—	$	(87)	$	(128)

  SOUTHERN COMPANYD-53

NOTES (continued)

2. RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2014, certain of the traditional operating companies and other subsidiaries voluntarily contributed an aggregate of $500 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. 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 other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2015, other postretirement trust contributions are expected to total approximately $19 million.

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 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%.

	2014			2013			2012
Discount rate:
Pension plans		4.17	%		5.02	%		4.26	%
Other postretirement benefit plans		4.04			4.85			4.05
Annual salary increase		3.59			3.59			3.59
Long-term return on plan assets:
Pension plans		8.20			8.20			8.20
Other postretirement benefit plans		7.15			7.13			7.29

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

For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company’s pension plans and other postretirement benefit plans by approximately $636 million and $92 million, respectively.

An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows:

	Initial Cost Trend Rate			Ultimate Cost Trend Rate			Year That Ultimate Rate is Reached
Pre-65		9.00	%		4.50	%		2024
Post-65 medical		6.00			4.50			2024
Post-65 prescription		6.75			4.50			2024

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, 2014 as follows:

	1 Percent Increase		1 Percent Decrease
	(in millions)
Benefit obligation	$	140	$	(117	)
Service and interest costs		6		(5	)

D-54  SOUTHERN COMPANY

NOTES (continued)

Pension Plans

The total accumulated benefit obligation for the pension plans was $10.0 billion at December 31, 2014 and $8.1 billion at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows:

	2014			2013
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	8,863		$	9,302
Service cost		213			232
Interest cost		435			389
Benefits paid		(382	)		(357	)
Actuarial (gain) loss		1,780			(703	)
Balance at end of year		10,909			8,863
Change in plan assets
Fair value of plan assets at beginning of year		8,733			7,953
Actual return on plan assets		797			1,098
Employer contributions		542			39
Benefits paid		(382	)		(357	)
Fair value of plan assets at end of year		9,690			8,733
Accrued liability	$	(1,219)		$	(130)

At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $10.3 billion and $617 million, respectively. All pension plan assets are related to the qualified pension plan.

Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company’s pension plans consist of the following:

	2014	2013
	(in millions)
Prepaid pension costs	$             —	$	419
Other regulatory assets, deferred	3,073		1,651
Other current liabilities	(42)		(40	)
Employee benefit obligations	(1,177)		(509	)
Accumulated OCI	134		64

Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2014 and 2013 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 2015.

	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2014:
Accumulated OCI	$	4	$	130
Regulatory assets		51		3,022
Total	$	55	$	3,152
Balance at December 31, 2013:
Accumulated OCI	$	5	$	59
Regulatory assets		75		1,575
Total	$	80	$	1,634
Estimated amortization in net periodic pension cost in 2015:
Accumulated OCI	$	1	$	9
Regulatory assets		24		206
Total	$	25	$	215

  SOUTHERN COMPANYD-55

NOTES (continued)

The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table:

	Accumulated OCI			Regulatory Assets
	(in millions)
Balance at December 31, 2012	$	125		$	3,013
Net gain		(52	)		(1,145	)
Change in prior service costs		—			1
Reclassification adjustments:
Amortization of prior service costs		(1	)		(26	)
Amortization of net gain (loss)		(8	)		(192	)
Total reclassification adjustments		(9	)		(218	)
Total change		(61	)		(1,362	)
Balance at December 31, 2013	$	64		$	1,651
Net gain		75			1,552
Change in prior service costs		—			1
Reclassification adjustments:
Amortization of prior service costs		(1	)		(25	)
Amortization of net gain (loss)		(4	)		(106	)
Total reclassification adjustments		(5	)		(131	)
Total change		70			1,422
Balance at December 31, 2014	$	134		$	3,073

Components of net periodic pension cost were as follows:

	2014			2013			2012
	(in millions)
Service cost	$	213		$	232		$	198
Interest cost		435			389			393
Expected return on plan assets		(645	)		(603	)		(581	)
Recognized net loss		110			200			95
Net amortization		26			27			30
Net periodic pension cost	$	139		$	245		$	135

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, 2014, estimated benefit payments were as follows:

	Benefit Payments
	(in millions)
2015	$	522
2016		450
2017		478
2018		499
2019		524
2020 to 2024		2,962

D-56  SOUTHERN COMPANY

NOTES (continued)

Other Postretirement Benefits

Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows:

	2014			2013
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,682		$	1,872
Service cost		21			24
Interest cost		79			74
Benefits paid		(102	)		(94	)
Actuarial (gain) loss		300			(200	)
Plan amendments		(2	)		—
Retiree drug subsidy		8			6
Balance at end of year		1,986			1,682
Change in plan assets
Fair value of plan assets at beginning of year		901			821
Actual return on plan assets		54			129
Employer contributions		39			39
Benefits paid		(94	)		(88	)
Fair value of plan assets at end of year		900			901
Accrued liability	$	(1,086	)	$	(781	)

Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company’s other postretirement benefit plans consist of the following:

	2014			2013
	(in millions)
Other regulatory assets, deferred	$	387		$	109
Other current liabilities		(4	)		(4	)
Employee benefit obligations		(1,082	)		(777	)
Other regulatory liabilities, deferred		(21	)		(36	)
Accumulated OCI		8			1

Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015.

	Prior Service Cost		Net (Gain) Loss
	(in millions)
Balance at December 31, 2014:
Accumulated OCI	$	—	$	8
Net regulatory assets (liabilities)		2		364
Total	$	2	$	372
Balance at December 31, 2013:
Accumulated OCI	$	—	$	1
Net regulatory assets (liabilities)		9		64
Total	$	9	$	65
Estimated amortization as net periodic postretirement benefit cost in 2015:
Accumulated OCI	$	—	$	—
Net regulatory assets (liabilities)		4		17
Total	$	4	$	17

  SOUTHERN COMPANYD-57

NOTES (continued)

The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table:

	Accumulated OCI			Net Regulatory Assets (Liabilities)
	(in millions)
Balance at December 31, 2012	$	7		$	360
Net loss		(6	)		(266	)
Reclassification adjustments:
Amortization of transition obligation		—			(5	)
Amortization of prior service costs		—			(4	)
Amortization of net gain (loss)		—			(12	)
Total reclassification adjustments		—			(21	)
Total change		(6	)		(287	)
Balance at December 31, 2013	$	1		$	73
Net gain		7			301
Change in prior service costs		—			(2	)
Reclassification adjustments:
Amortization of prior service costs		—			(4	)
Amortization of net gain (loss)		—			(2	)
Total reclassification adjustments		—			(6	)
Total change		7			293
Balance at December 31, 2014	$	8		$	366

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

	2014			2013			2012
	(in millions)
Service cost	$	21		$	24		$	21
Interest cost		79			74			85
Expected return on plan assets		(59	)		(56	)		(60	)
Net amortization		6			21			20
Net periodic postretirement benefit cost	$	47		$	63		$	66

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:

	Benefit Payments		Subsidy Receipts			Total
	(in millions)
2015	$	118	$	(10	)	$	108
2016		124		(11	)		113
2017		129		(12	)		117
2018		132		(13	)		119
2019		134		(15	)		119
2020 to 2024		670		(79	)		591

D-58  SOUTHERN COMPANY

NOTES (continued)

Benefit Plan Assets

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

The composition of the Company’s pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below:

	Target			2014			2013
Pension plan assets:
Domestic equity		26	%		30	%		31	%
International equity		25			23			25
Fixed income		23			27			23
Special situations		3			1			1
Real estate investments		14			14			14
Private equity		9			5			6
Total		100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity		42	%		41	%		40	%
International equity		21			23			25
Domestic fixed income		24			26			24
Global fixed income		4			3			4
Special situations		1			—			—
Real estate investments		5			5			5
Private equity		3			2			2
Total		100	%		100	%		100	%

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

Investment Strategies

Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:

• Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

• International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.

• Fixed income. A mix of domestic and international bonds.

• Trust-owned life insurance (TOLI). Investments of the Company’s taxable trusts aimed at minimizing the impact of taxes on the portfolio.

• Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

• Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.

  SOUTHERN COMPANYD-59

NOTES (continued)

• Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

Benefit Plan Asset Fair Values

Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:

• Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

• Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

• TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy’s separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

• Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.

	Fair Value Measurements Using
As of December 31, 2014:		Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	1,704		$	704	$	—	$	2,408
International equity*		1,070			986		—		2,056
Fixed income:
U.S. Treasury, government, and agency bonds		—			699		—		699
Mortgage- and asset-backed securities		—			188		—		188
Corporate bonds		—			1,135		—		1,135
Pooled funds		—			514		—		514
Cash equivalents and other		3			660		—		663
Real estate investments		293			—		1,121		1,414
Private equity		—			—		570		570
Total	$	3,070		$	4,886	$	1,691	$	9,647
Liabilities:
Derivatives	$	(2	)	$	—	$	—	$	(2	)
Total	$	3,068		$	4,886	$	1,691	$	9,645

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

D-60  SOUTHERN COMPANY

NOTES (continued)

	Fair Value Measurements Using
As of December 31, 2013:		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	1,433	$	839		$	—	$	2,272
International equity*		1,101		1,018			—		2,119
Fixed income:
U.S. Treasury, government, and agency bonds		—		599			—		599
Mortgage- and asset-backed securities		—		156			—		156
Corporate bonds		—		978			—		978
Pooled funds		—		471			—		471
Cash equivalents and other		1		223			—		224
Real estate investments		260		—			1,000		1,260
Private equity		—		—			571		571
Total	$	2,795	$	4,284		$	1,571	$	8,650
Liabilities:
Derivatives	$	—	$	(3	)	$	—	$	(3	)
Total	$	2,795	$	4,281		$	1,571	$	8,647

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

Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows:

	2014					2013
	Real Estate Investments		Private Equity			Real Estate Investments		Private Equity
	(in millions)
Beginning balance	$	1,000	$	571		$	841	$	593
Actual return on investments:
Related to investments held at year end		79		51			74		8
Related to investments sold during the year		33		(16	)		30		51
Total return on investments		112		35			104		59
Purchases, sales, and settlements		9		(36	)		55		(81	)
Ending balance	$	1,121	$	570		$	1,000	$	571

The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.

  SOUTHERN COMPANYD-61

NOTES (continued)

	Fair Value Measurements Using
As of December 31, 2014:		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	147	$	56	$	—	$	203
International equity*		36		67		—		103
Fixed income:
U.S. Treasury, government, and agency bonds		—		29		—		29
Mortgage- and asset-backed securities		—		6		—		6
Corporate bonds		—		39		—		39
Pooled funds		—		41		—		41
Cash equivalents and other		9		27		—		36
Trust-owned life insurance		—		381		—		381
Real estate investments		11		—		37		48
Private equity		—		—		19		19
Total	$	203	$	646	$	56	$	905

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

	Fair Value Measurements Using
As of December 31, 2013:		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Assets:
Domestic equity*	$	157	$	45	$	—	$	202
International equity*		39		82		—		121
Fixed income:
U.S. Treasury, government, and agency bonds		—		34		—		34
Mortgage- and asset-backed securities		—		6		—		6
Corporate bonds		—		35		—		35
Pooled funds		—		46		—		46
Cash equivalents and other		—		19		—		19
Trust-owned life insurance		—		369		—		369
Real estate investments		10		—		36		46
Private equity		—		—		20		20
Total	$	206	$	636	$	56	$	898

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

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Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows:

	2014					2013
	Real Estate Investments		Private Equity			Real Estate Investments		Private Equity
	(in millions)
Beginning balance	$	36	$	20		$	30	$	21
Actual return on investments:
Related to investments held at year end		1		1			3		—
Related to investments sold during the year		—		(1	)		1		2
Total return on investments		1		—			4		2
Purchases, sales, and settlements		—		(1	)		2		(3	)
Ending balance	$	37	$	19		$	36	$	20

Employee Savings Plan

Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee’s base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $87 million, $84 million, and $82 million, respectively.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements.

Insurance Recovery

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 other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.

In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors’ committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant’s plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received payments from its insurance provider of $25 million in June 2012 and $15 million in December 2013. Additionally, legal fees related to these insurance settlements totaled approximately $6 million in 2012 and $4 million in 2013. As a result, the net reduction to expense presented as MC Asset Recovery insurance settlement in the statement of income was approximately $19 million in 2012 and $11 million in 2013.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit

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co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.

Southern Company believes the traditional operating companies complied with applicable laws and regulations 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, depending on the date of the alleged violation. An adverse outcome could require substantial 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. The ultimate outcome of these matters cannot be determined at this time.

Environmental Remediation

The Southern Company system 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 Southern Company system could 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. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power’s environmental remediation liability as of December 31, 2014 was $22 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 site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO.

In addition to the EPA’s action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power’s summary judgment motion, ruling that Georgia Power has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division’s order to the U.S. Court of Appeals for the Fourth Circuit.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power’s regulatory treatment for environmental remediation expenses, these matters are 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 $48 million as of December 31, 2014. 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 is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, these liabilities have no impact on net income.

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

Nuclear Fuel Disposal Costs

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet

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to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system’s direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.

On December 12, 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power was awarded approximately $18 million, based on its ownership interests, and Alabama Power was awarded approximately $26 million. No amounts have been recognized in the financial statements as of December 31, 2014. The final outcome of this matter cannot be determined at this time; however, no material impact on Southern Company’s net income is expected.

On March 4, 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company’s net income is expected.

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

Retail Regulatory Matters

Alabama Power

Rate RSE

Alabama Power’s Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power’s actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. Prior to 2014, retail rates remained unchanged when the retail ROE was projected to be between 13.0% and 14.5%.

During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. In August 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power’s Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE.

• Eliminate the provision of Rate RSE limiting Alabama Power’s capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon the WCE range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

• Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an “A” credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE were unchanged.

In August 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. In November 2013, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%.

On December 1, 2014, Alabama Power submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%.

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Rate CNP

Alabama Power’s retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015. As of December 31, 2014, Alabama Power had an under recovered certificated PPA balance of $56 million, of which $27 million is included in under recovered regulatory clause revenues and $29 million is included in deferred under recovered regulatory clause revenues in the balance sheet.

In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 MWs of electricity from wind-powered generating facilities that became operational in 2012. In 2012, the Alabama PSC approved and certificated a second PPA of approximately 200 MWs of electricity from other wind-powered generating facilities which became operational in 2014. The terms of the PPAs permit Alabama Power to use the energy and retire the associated environmental attributes in service of its customers or to sell the environmental attributes, separately or bundled with energy. Alabama Power has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry’s application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF’s deliberations cannot be determined at this time. If Alabama Power is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded.

Rate CNP Environmental allows for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP Environmental in 2014. In August 2013, the Alabama PSC approved Alabama Power’s petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The Rate CNP Environmental increase effective January 1, 2015 was 1.5%, or $75 million annually, based upon projected billings. As of December 31, 2014, Alabama Power had an under recovered environmental clause balance of $49 million, of which $47 million is included in under recovered regulatory clause revenues and $2 million is included in deferred under recovered regulatory clause revenues in the balance sheet.

Rate ECR

Alabama Power has established energy cost recovery rates under Alabama Power’s Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the energy cost recovery rates which began in 2011. Therefore, the Rate ECR factor as of January 1, 2015 remained at 2.681 cents per KWH. Effective with billings beginning in January 2016, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC.

Alabama Power’s over recovered fuel costs at December 31, 2014 totaled $47 million as compared to over recovered fuel costs of $42 million at December 31, 2013. At December 31, 2014, $47 million is included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs.

Rate NDR

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer

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account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power’s approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company’s financial statements.

Nuclear Waste Fund Accounting Order

In November 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. In accordance with the court’s order, the DOE submitted a proposal to the U.S. Congress to change the fee to zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE’s request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014.

On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). At December 31, 2014, Alabama Power recorded an $8 million regulatory liability which is included in other regulatory liabilities deferred in the balance sheet. Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers, subject to the approval of the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time.

Compliance and Pension Cost Accounting Order

In 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs would have been amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events.

On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, including the $28 million of compliance and pension costs accumulated at December 31, 2014. This amortization expense was offset by the amortization of the regulatory liability for other cost of removal obligations. See “Cost of Removal Accounting Order” herein for additional information. The cost of removal accounting order requires

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Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.

Non-Nuclear Outage Accounting Order

In August 2013, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015.

On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, including the $95 million of non-nuclear outage costs accumulated at December 31, 2014. This amortization expense was reflected in other operations and maintenance and was offset by the amortization of the regulatory liability for other cost of removal obligations. See “Cost of Removal Accounting Order” herein for additional information. The cost of removal accounting order requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the non-nuclear outage accounting order.

Cost of Removal Accounting Order

In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, as discussed herein.

Non-Environmental Federal Mandated Costs Accounting Order

On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015.

On February 17, 2015, Alabama Power filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power’s facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Rate Plans

In December 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC in November 2013.

On January 1, 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million.

On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved adjustments to traditional base, ECCR, DSM, and MFF tariffs effective January 1, 2015 as follows:

• Traditional base tariffs by approximately $107 million to cover additional capacity costs;

• ECCR tariff by approximately $23 million;

• DSM tariffs by approximately $3 million; and

• MFF tariff by approximately $3 million to reflect the adjustments above.

The sum of these adjustments resulted in a base revenue increase of approximately $136 million in 2015.

The 2016 base rate increase, which was approved in the 2013 ARP, will be determined through a compliance filing expected to be filed in late 2015, and will be subject to review by the Georgia PSC.

Under the 2013 ARP, Georgia Power’s retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-

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third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, Georgia Power projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust Georgia Power’s earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on Georgia Power’s request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case. In 2014, Georgia Power’s retail ROE exceeded 12.00%, and Georgia Power expects to refund to retail customers approximately $13 million in 2015, subject to review and approval by the Georgia PSC.

Except as provided above, Georgia Power will not file for a general base rate increase while the 2013 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.

Integrated Resource Plans

In July 2013, the Georgia PSC approved Georgia Power’s latest triennial Integrated Resource Plan (2013 IRP) including Georgia Power’s request to decertify 16 coal- and oil-fired units totaling 2,093 MWs. Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units.

Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the Mercury and Air Toxics Standards (MATS) rule. The decertification date of Plant Branch Unit 1 (250 MWs) was extended from December 31, 2013 as specified in the final order in the 2011 Integrated Resource Plan Update (2011 IRP Update) to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) were also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division in September 2013 to allow for necessary transmission system reliability improvements. In July 2013, the Georgia PSC approved the switch to natural gas as the primary fuel for Plant Yates Units 6 and 7. In September 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP Update in order to comply with the State of Georgia’s Multi-Pollutant Rule.

In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to Georgia Power’s next base rate case, which Georgia Power expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.

On July 1, 2014, the Georgia PSC approved Georgia Power’s request to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. Georgia Power expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan to be filed in 2016. Georgia Power plans to continue to operate the unit as needed until the MATS rule becomes effective in April 2015.

The decertification of these units and fuel conversions are not expected to have a material impact on Southern Company’s financial statements; however, the ultimate outcome depends on the Georgia PSC’s order in the 2016 Rate Case and future fuel cases and cannot be determined at this time.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power’s total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power’s fuel cost recovery includes costs associated with a natural gas hedging program as revised and approved by the Georgia PSC in February 2013, requiring it to use options and hedges within a 24-month time horizon. See Note 11 under “Energy-Related Derivatives” for additional information. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power’s next fuel case filing until at least June 30, 2015.

Georgia Power’s under recovered fuel balance totaled approximately $199 million at December 31, 2014 and is included in current assets and other deferred charges and assets. At December 31, 2013, Georgia Power’s over recovered fuel balance totaled approximately $58 million and was included in current liabilities and other deferred credits and liabilities.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect cash flow.

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Storm Damage Recovery

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $98 million and $37 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $68 million and $7 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company’s financial statements.

Nuclear Construction

In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor’s failure to fulfill the schedule and performance guarantees. The Contractor’s liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power’s ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share is 45.7%.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and CB&I’s The Shaw Group Inc., respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle 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 Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On December 16, 2014, the Georgia PSC approved an increase to the NCCR tariff of approximately $27 million effective January 1, 2015.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor’s suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of

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additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power’s ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power’s ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power’s eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively.

In September 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. In addition, financing costs on any construction-related costs in excess of the certified amount likely would be subject to recovery through AFUDC instead of the NCCR tariff.

The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

On January 29, 2015, Georgia Power announced that it was notified by the Contractor of the Contractor’s revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4). Georgia Power has not agreed to any changes to the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Georgia Power does not believe that the Contractor’s revised forecast reflects all efforts that may be possible to mitigate the Contractor’s delay.

In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor’s costs related to the Contractor’s delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor’s delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor’s position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor’s delay.

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requests approval for an additional $0.2 billion of construction capital costs incurred during that period and reflects the Contractor’s revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs of approximately $10 million per month expected to result from the Contractor’s proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor’s proposed 18-month delay are included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report includes a requested amendment to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor’s revised forecast, to include the estimated owner’s costs associated with the proposed 18-month Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.

Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimates total associated financing costs during the construction period to be approximately $2.5 billion.

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Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.

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

Gulf Power

Retail Base Rate Case

In December 2013, the Florida PSC voted to approve the Gulf Power Settlement Agreement among Gulf Power and all of the intervenors to the docketed proceeding with respect to Gulf Power’s request to increase retail base rates. Under the terms of the Gulf Power Settlement Agreement, Gulf Power (1) increased base rates designed to produce an additional $35 million in annual revenues effective January 2014 and subsequently increased base rates designed to produce an additional $20 million in annual revenues effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) will accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until Gulf Power’s next base rate adjustment date or January 1, 2017, whichever comes first.

The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.

The Gulf Power Settlement Agreement also provides that Gulf Power may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power’s next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. As a result, Gulf Power recognized an $8.4 million reduction in depreciation expense in 2014.

Pursuant to the Gulf Power Settlement Agreement, Gulf Power may not request an increase in its retail base rates to be effective until after June 2017, unless Gulf Power’s actual retail ROE falls below the authorized ROE range.

Integrated Coal Gasification Combined Cycle

Kemper IGCC Overview

Construction of Mississippi Power’s Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants)

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and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC.

The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on natural gas on August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016.

Recovery of the Kemper IGCC cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) and costs subject to the cost cap remain subject to review and approval by the Mississippi PSC. Mississippi Power’s Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court’s (Court) decision), and actual costs incurred as of December 31, 2014, as adjusted for the Court’s decision, are as follows:

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at 12/31/2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.93	$	4.23
Lignite Mine and Equipment		0.21		0.23		0.23
CO2 Pipeline Facilities		0.14		0.11		0.10
AFUDC(b)(c)		0.17		0.63		0.45
Combined Cycle and Related Assets Placed in Service – Incremental(d)		—		0.02		0.00
General Exceptions		0.05		0.10		0.07
Deferred Costs(c)(e)		—		0.18		0.12
Total Kemper IGCC(a)(c)	$	2.97	$	6.20	$	5.20

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See “Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order” for additional information.

(b) Mississippi Power’s original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in “Rate Recovery of Kemper IGCC Costs.”

(c) Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales. See “Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order” for additional information.

(e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in “Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities.”

(f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2014, $3.04 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.05 billion), $1.8 million in other property and investments, $44.7 million in fossil fuel stock, $32.5 million in materials and supplies, $147.7 million in other regulatory assets, $11.6 million in other deferred charges and assets, and $23.6 million in AROs in the balance sheet, with $1.1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868.0 million ($536.0 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in 2014 primarily reflected costs related to extension of the project’s schedule to ensure the required time for start-up activities and operational readiness, completion of construction, additional resources during start-up, and ongoing construction support during start-up and commissioning activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational

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resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company’s results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power’s recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power’s recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the Rate Mitigation Plan (defined below) and other related proceedings during the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on the financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See “2015 Mississippi Supreme Court Decision” below for additional information.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power’s intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as approved by the Mississippi PSC.

The Court’s decision did not impact Mississippi Power’s ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See “2015 Mississippi Supreme Court Decision” below for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. For the period from March 2013 through December 31, 2014, $257.2 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.

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Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC.

On August 18, 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power’s analysis requested, among other things, confirmation of Mississippi Power’s accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See “2015 Mississippi Supreme Court Decision” for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.

In addition, Mississippi Power’s August 18, 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power’s accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power’s proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See “Regulatory Assets and Liabilities” for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. The Court’s ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court’s ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through December 31, 2014, Mississippi Power had collected $257.2 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court’s decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the Mississippi PSC will determine the method and timing of the refund. Mississippi Power is reviewing the Court’s decision and expects to file a motion for rehearing which would stay the Court’s mandate until either the case is reheard and decided or seven days after the Court issues its order denying Mississippi Power’s request for rehearing. Mississippi Power is also evaluating its regulatory options.

Rate Mitigation Plan

In March 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015. In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power’s proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year’s rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See “Regulatory Assets and Liabilities” for additional information.

  SOUTHERN COMPANYD-75

NOTES (continued)

To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See “2015 Mississippi Supreme Court Decision” above for additional information.

In the event that the Mirror CWIP regulatory liability is refunded to customers prior to the in-service date of the Kemper IGCC and is, therefore, not available to mitigate rate impacts under the Rate Mitigation Plan, the Mississippi PSC does not approve a refund schedule that facilitates rate mitigation, or Mississippi Power withdraws the Rate Mitigation Plan, Mississippi Power would seek rate recovery through alternate means, which could include a traditional rate case.

In addition to current estimated costs at December 31, 2014 of $6.2 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC’s review of Kemper IGCC costs is ongoing. On August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS. The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court’s decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See “2015 Mississippi Supreme Court Decision” for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

On August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power’s authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of December 31, 2014, the regulatory asset balance associated with the Kemper IGCC was $147.7 million. The projected balance at March 31, 2016 is estimated to total approximately $269.8 million. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

The 2013 MPSC Rate Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of December 31, 2014, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $270.8 million.

See “2015 Mississippi Supreme Court Decision” for additional information.

See Note 1 under “Regulatory Assets and Liabilities” for additional information.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

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NOTES (continued)

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO₂ by May 11, 2015. While Mississippi Power has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination could result in a material reduction in future chemical product sales revenues but is not expected to have a material financial impact on Southern Company to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $16.7 million in 2014. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA’s option to purchase through December 31, 2014.

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA’s proposed purchase of a 15% undivided interest in the Kemper IGCC. The letter agreement contemplated certain amendments to the APA, which the parties anticipated to be incorporated into the APA on or before December 31, 2014. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA’s deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service.

By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA’s receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

In 2012, on January 2, 2014, and on October 9, 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposits and SMEPA’s ability to request a refund, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

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

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. 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

  SOUTHERN COMPANYD-77

NOTES (continued)

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. In the 2015 Mississippi Supreme Court decision, the Court declined to rule on the constitutionality of the Baseload Act. See “Rate Recovery of Kemper IGCC Costs” herein for additional information.

Investment Tax Credits and Bonus Depreciation

The IRS allocated $279.0 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through December 31, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $210.0 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA’s proposed purchase of an undivided interest in the Kemper IGCC as described above.

On December 19, 2014, the Tax Increase Prevention Act of 2014 (TIPA) was signed into law. The TIPA retroactively extended several tax credits through 2014 and extended 50% bonus depreciation for property placed in service in 2014 (and for certain long-term production-period projects to be placed in service in 2015). The extension of 50% bonus depreciation had a positive impact on Southern Company’s cash flows and, combined with bonus depreciation allowed in 2014 under the ATRA, resulted in approximately $130 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2014 tax year. The estimated cash flow benefit of bonus depreciation related to TIPA is expected to be approximately $45 million to $50 million for the 2015 tax year. See “Rate Recovery of Kemper IGCC Costs – Rate Mitigation Plan” herein for additional information.

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

Section 174 Research and Experimental Deduction

Southern Company reduced tax payments for 2014 and included in its 2013 consolidated federal income tax return deductions for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $160 million as of December 31, 2014. See Note 5 under “Unrecognized Tax Benefits” for additional information.

Other Matters

Sierra Club Settlement Agreement

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the flue gas desulfurization system (scrubber) project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC and the Plant Daniel Units 1 and 2 scrubber project, which the applicable courts subsequently granted.

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in 2014, recognized in other income (expense), net in Southern Company’s statement of income. In addition, and consistent with Mississippi Power’s ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016.

4. JOINT OWNERSHIP AGREEMENTS

Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light

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NOTES (continued)

Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Duke Energy Florida, Inc. 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, 2014, Alabama Power’s, Georgia Power’s, and Southern Power’s percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:

Facility (Type)	Percent Ownership			Plant in Service		Accumulated Depreciation		CWIP
			(in millions)
Plant Vogtle (nuclear) Units 1 and 2	45.7	%	$	3,420	$	2,059	$	46
Plant Hatch (nuclear)	50.1			1,117		559		66
Plant Miller (coal) Units 1 and 2	91.8			1,512		561		14
Plant Scherer (coal) Units 1 and 2	8.4			254		83		1
Plant Wansley (coal)	53.5			856		278		15
Rocky Mountain (pumped storage)	25.4			182		124		2
Intercession City (combustion turbine)	33.3			14		5		—
Plant Stanton (combined cycle) Unit A	65.0			157		47		—

Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” for additional information.

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, combined state income tax returns for the States of Alabama, Georgia, and Mississippi, and unitary income tax returns for the States of California, North Carolina, and Texas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2014		2013			2012
	(in millions)
Federal —
Current	$	175	$	363		$	177
Deferred		695		386			1,011
		870		749			1,188
State —
Current		93		(10	)		61
Deferred		14		110			85
		107		100			146
Total	$	977	$	849		$	1,334

Net cash payments for income taxes in 2014, 2013, and 2012 were $272 million, $139 million, and $38 million, respectively.

  SOUTHERN COMPANYD-79

NOTES (continued)

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:

	2014			2013
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	11,125		$	9,710
Property basis differences		1,332			1,515
Leveraged lease basis differences		299			287
Employee benefit obligations		613			491
Premium on reacquired debt		103			113
Regulatory assets associated with employee benefit obligations		1,390			705
Regulatory assets associated with AROs		871			824
Other		523			350
Total		16,256			13,995
Deferred tax assets —
Federal effect of state deferred taxes		430			421
Employee benefit obligations		1,675			1,048
Over recovered fuel clause		—			30
Other property basis differences		453			157
Deferred costs		86			84
ITC carryforward		480			121
Unbilled revenue		67			116
Other comprehensive losses		89			54
AROs		871			824
Estimated Loss on Kemper IGCC		631			472
Deferred state tax assets		117			77
Other		342			220
Total		5,241			3,624
Valuation allowance		(49	)		(49	)
Total deferred tax assets		5,192			3,575
Total deferred tax liabilities, net		11,064			10,420
Portion included in current assets/(liabilities), net		504			143
Accumulated deferred income taxes	$	11,568		$	10,563

The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation.

At December 31, 2014, Southern Company had subsidiaries with State of Georgia net operating loss (NOL) carryforwards totaling $701 million, which could result in net state income tax benefits of $41 million, if utilized. However, the subsidiaries have established a valuation allowance for the entire amount due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 2018 and 2021. Beginning in 2002, the State of Georgia allowed Southern Company to file a combined return, which has prevented the creation of any additional NOL carryforwards.

At December 31, 2014, the tax-related regulatory assets to be recovered from customers were $1.5 billion. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.

At December 31, 2014, the tax-related regulatory liabilities to be credited to customers were $192 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.

In accordance with regulatory requirements, deferred federal ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2014, $16 million in 2013, and $23 million in 2012. At December 31, 2014, Southern Company had a federal ITC carryforward which is expected to result in $379 million of federal income tax benefit. The ITC carryforward expires in 2023, but is expected to be utilized in 2015. Additionally, Southern Company had state ITC carryforwards for the states of Georgia and Mississippi totaling $159 million, which will expire between 2020 and 2024.

D-80  SOUTHERN COMPANY

NOTES (continued)

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	2014			2013			2012
Federal statutory rate		35.0	%		35.0	%		35.0	%
State income tax, net of federal deduction		2.3			2.5			2.5
Employee stock plans dividend deduction		(1.4	)		(1.6	)		(1.0	)
Non-deductible book depreciation		1.4			1.5			0.9
AFUDC-Equity		(2.9	)		(2.6	)		(1.3	)
ITC basis difference		(1.6	)		(1.2	)		(0.3	)
Other		(0.3	)		(0.5	)		(0.2	)
Effective income tax rate		32.5	%		33.1	%		35.6	%

Southern Company’s effective tax rate is typically lower than the statutory rate due to its employee stock plans’ dividend deduction and non-taxable AFUDC equity. The 2014 effective tax rate decrease, as compared to 2013, is primarily due to an increase in non-taxable AFUDC equity and an increase in tax benefits related to federal ITCs. Additionally, the 2013 effective rate decrease, as compared to 2012, is primarily due to an increase in non-taxable AFUDC equity.

Unrecognized Tax Benefits

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

	2014			2013			2012
	(in millions)
Unrecognized tax benefits at beginning of year	$	7		$	70		$	120
Tax positions increase from current periods		64			3			13
Tax positions increase from prior periods		102			—			7
Tax positions decrease from prior periods		(3	)		(66	)		(56	)
Reductions due to settlements		—			—			(10	)
Reductions due to expired statute of limitations		—			—			(4	)
Balance at end of year	$	170		$	7		$	70

The tax positions increase from current periods and increase from prior periods for 2014 relate primarily to a deduction for R&E expenditures related to the Kemper IGCC. See Note 3 under “Integrated Coal Gasification Combined Cycle – Section 174 Research and Experimental Deduction” for more information. The tax positions decrease from prior periods for 2013 relate primarily to the tax accounting method change for repairs related to generation assets. See “Tax Method of Accounting for Repairs” herein for additional information.

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

	2014		2013		2012
	(in millions)
Tax positions impacting the effective tax rate	$	10	$	7	$	5
Tax positions not impacting the effective tax rate		160		—		65
Balance of unrecognized tax benefits	$	170	$	7	$	70

The tax positions impacting the effective tax rate for 2014, 2013, and 2012 relate to federal and state income tax credits. The tax positions not impacting the effective tax rate for 2014 relate to a deduction for R&E expenditures related to the Kemper IGCC. The tax positions not impacting the effective tax rate for 2012 relate to the tax accounting method change for repairs related to generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Southern Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. Southern Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

  SOUTHERN COMPANYD-81

NOTES (continued)

The IRS has finalized its audits of Southern Company’s consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company’s state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2008.

Tax Method of Accounting for Repairs

In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, “Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property,” which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company’s financial statements.

6. FINANCING

Long-Term Debt Payable to an Affiliated Trust

Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million as of December 31, 2014 and 2013, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust’s payment obligations with respect to these securities. At each of December 31, 2014 and 2013, trust preferred securities of $200 million were outstanding.

Securities Due Within One Year

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

	2014		2013
	(in millions)
Senior notes	$	2,375	$	428
Other long-term debt		775		12
Pollution control revenue bonds		152		—
Capitalized leases		31		29
Total	$	3,333	$	469

Maturities through 2019 applicable to total long-term debt are as follows: $3.33 billion in 2015; $1.83 billion in 2016; $1.55 billion in 2017; $862 million in 2018; and $1.21 billion in 2019.

Subsequent to December 31, 2014, Alabama Power announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035 that will occur on March 16, 2015.

Bank Term Loans

Southern Company and certain of the traditional operating companies have entered into various floating rate bank term loan agreements for loans bearing interest based on one-month LIBOR. At December 31, 2014, Mississippi Power had outstanding bank term loans totaling $775 million, which are reflected in the statements of capitalization as long-term debt. At December 31, 2013, Mississippi Power had outstanding bank term loans totaling $525 million and Georgia Power had outstanding bank term loans totaling $400 million.

In January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power’s continuous construction program.

In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.

D-82  SOUTHERN COMPANY

NOTES (continued)

In June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014.

The outstanding bank loans as of December 31, 2014, all of which relate to Mississippi Power, have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, other hybrid securities, and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2014, Mississippi Power was in compliance with its debt limits.

DOE Loan Guarantee Borrowings

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.

Proceeds of advances made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.

All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power’s reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power’s rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power’s ability to grant liens on other property.

Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.

On December 11, 2014, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million. The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044.

Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, compliance with the Cargo Preference Act of 1954, and certification from the DOE’s consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events occur, the FFB’s commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

  SOUTHERN COMPANYD-83

NOTES (continued)

In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power’s rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power’s ownership interest in Plant Vogtle Units 3 and 4.

Senior Notes

Southern Company and its subsidiaries issued a total of $1.4 billion of senior notes in 2014. Southern Company issued $750 million and its subsidiaries issued a total of $600 million. The proceeds of these issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries’ continuous construction programs.

At December 31, 2014 and 2013, Southern Company and its subsidiaries had a total of $18.2 billion and $17.3 billion, respectively, of senior notes outstanding. At December 31, 2014 and 2013, Southern Company had a total of $2.2 billion and $1.8 billion, respectively, of senior notes outstanding.

Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary.

Pollution Control Revenue Bonds

Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of pollution control bonds issued by public authorities. The traditional operating companies had $3.2 billion of outstanding pollution control revenue bonds at December 31, 2014 and 2013. The traditional operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.

Plant Daniel Revenue Bonds

In 2011, in connection with Mississippi Power’s election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See “Assets Subject to Lien” herein for additional information.

Other Revenue Bonds

Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities.

In November 2013, the MBFC entered into an agreement to issue up to $33.75 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013A (Mississippi Power Company Project) and up to $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013B (Mississippi Power Company Project) for the benefit of Mississippi Power. In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. In December 2014, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A of $22.87 million and Series 2013B of $11.25 million were paid at maturity.

Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2014 and 2013. Mississippi Power had no obligation at December 31, 2014 and $11.3 million of such obligations related to taxable revenue bonds outstanding at December 31, 2013. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt.

Mississippi Power’s agreements relating to its taxable revenue bonds include covenants limiting debt levels consistent with those described above under “Bank Term Loans.”

Capital Leases

Assets acquired under capital leases are recorded in the balance sheets as utility plant in service and the related obligations are classified as long-term debt.

D-84  SOUTHERN COMPANY

NOTES (continued)

In September 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2014 of approximately $80 million with an annual interest rate of 4.9%. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service.

At December 31, 2014 and 2013, the capitalized lease obligations for Georgia Power’s corporate headquarters building were $40 million and $45 million, respectively, with an annual interest rate of 7.9% for both years.

At December 31, 2014 and 2013, Alabama Power had a capitalized lease obligation of $5 million for a natural gas pipeline with an annual interest rate of 6.9%.

At December 31, 2014 and 2013, a subsidiary of Southern Company had capital lease obligations of approximately $34 million and $30 million, respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.4% to 3.2%.

Other Obligations

In 2012, January 2014, and October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power’s AFUDC rate adjusted for income taxes, which was 10.134% per annum for 2014, 9.932% per annum for 2013, and 9.967% per annum for 2012, and are refundable to SMEPA upon termination of the APA related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

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. There are no agreements or other arrangements among the Southern Company system 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.

Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $41 million as of December 31, 2014.

The revenue bonds assumed in conjunction with Mississippi Power’s purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See “Plant Daniel Revenue Bonds” herein for additional information.

See “DOE Loan Guarantee Borrowings” above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power’s rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.

Bank Credit Arrangements

At December 31, 2014, committed credit arrangements with banks were as follows:

Company	Expires								Total		Unused		Executable Term Loans				Due Within One Year
	2015		2016		2017		2018						One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power		228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power		80		165		30		—		275		275		50		—		50		30
Mississippi Power		135		165		—		—		300		300		25		40		65		70
Southern Power		—		—		—		500		500		488		—		—		—		—
Other		70		—		—		—		70		70		20		—		20		50
Total	$	513	$	530	$	30	$	4,130	$	5,203	$	5,177	$	153	$	40	$	193	$	320

  SOUTHERN COMPANYD-85

NOTES (continued)

Most of the bank 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 less than ¹/₄ of 1% for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew their bank credit arrangements as needed, prior to expiration.

Most of these bank credit arrangements contain 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 and, for Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2014, Southern Company, the traditional operating companies, and Southern Power were each in compliance with their respective debt limit covenants.

A portion of the $5.2 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014 was approximately $1.8 billion. In addition, at December 31, 2014, the traditional operating companies had $476 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. As of December 31, 2014, $98 million of certain pollution control revenue bonds of Georgia Power were reclassified to securities due within one year in anticipation of their redemption in connection with unit retirement decisions. See Note 3 under “Retail Regulatory Matters – Georgia Power – Integrated Resource Plans” for additional information.

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at the End of the Period
	Amount Outstanding		Weighted Average Interest Rate
	(in millions)
December 31, 2014:
Commercial paper	$	803		0.3%
Short-term bank debt		—		—%
Total	$	803		0.3%
December 31, 2013:
Commercial paper	$	1,082		0.2%
Short-term bank debt		400		0.9%
Total	$	1,482		0.4%

Redeemable Preferred Stock of Subsidiaries

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

There were no changes for the years ended December 31, 2014 and 2013 in redeemable preferred stock of subsidiaries for Southern Company.

D-86  SOUTHERN COMPANY

NOTES (continued)

7. COMMITMENTS

Fuel and Purchased Power Agreements

To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the traditional operating companies and Southern Power incurred fuel expense of $6.0 billion, $5.5 billion, and $5.1 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system’s future fuel needs will continue to be purchased under long-term commitments.

In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $198 million, $157 million, and $171 million for 2014, 2013, and 2012, respectively.

Estimated total obligations under these commitments at December 31, 2014 were as follows:

	Operating Leases (1)		Other
	(in millions)
2015	$	230	$	11
2016		234		11
2017		264		10
2018		270		7
2019		274		6
2020 and thereafter		1,980		50
Total	$	3,252	$	95

(1) A total of $1.1 billion of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action.

Operating Leases

The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $118 million, $123 million, and $155 million for 2014, 2013, and 2012, 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.

As of December 31, 2014, estimated minimum lease payments under operating leases were as follows:

	Minimum Lease Payments
	Barges & Railcars		Other		Total
	(in millions)
2015	$	50	$	50	$	100
2016		41		48		89
2017		18		47		65
2018		9		35		44
2019		6		23		29
2020 and thereafter		20		228		248
Total	$	144	$	431	$	575

For the traditional operating companies, a majority of the barge and railcar 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 have terms expiring through 2024 with maximum obligations under these leases of $53 million. At the termination of the leases, the lessee may renew the lease or 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.

  SOUTHERN COMPANYD-87

NOTES (continued)

Guarantees

In December 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.

As discussed above under “Operating Leases,” Alabama Power and Georgia Power have entered into certain residual value guarantees.

8. COMMON STOCK

Stock Issued

During 2014, Southern Company issued approximately 20.8 million shares of common stock (including approximately 5.0 million treasury shares) for approximately $806 million through the employee and director stock plans and the Southern Investment Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators.

From August 2013 through December 2014, Southern Company used shares held in treasury, to the extent available, and newly issued shares to satisfy the requirements under the Southern Investment Plan and the employee savings plan. Beginning in January 2015, Southern Company ceased issuing additional shares under the Southern Investment Plan and the employee savings plan. All sales under these plans are now being funded with shares acquired on the open market by the independent plan administrators.

Beginning in 2015, Southern Company expects to repurchase shares of common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises. The Southern Company Board of Directors has approved the repurchase of up to 20 million shares of common stock for such purpose until December 31, 2017. Repurchases may be made by means of open market purchases, privately negotiated transactions, or accelerated or other share repurchase programs, in accordance with applicable securities laws.

Shares Reserved

At December 31, 2014, a total of 93 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 stock options and performance shares units as discussed below). Of the total 93 million shares reserved, there were 15 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2014.

Stock Options

Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 2014, there were 5,437 current and former employees participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.

The estimated fair values of stock options granted 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	2014	2013	2012
Expected volatility	14.6%	16.6%	17.7%
Expected term (in years)	5	5	5
Interest rate	1.5%	0.9%	0.9%
Dividend yield	4.9%	4.4%	4.2%
Weighted average grant-date fair value	$2.20	$2.93	$3.39

D-88  SOUTHERN COMPANY

NOTES (continued)

Southern Company’s activity in the stock option program for 2014 is summarized below:

	Shares Subject to Option	Weighted Average Exercise Price
Outstanding at December 31, 2013	38,819,366	$38.64
Granted	12,812,691	41.40
Exercised	11,585,363	35.06
Cancelled	117,375	42.72
Outstanding at December 31, 2014	39,929,319	$40.55
Exercisable at December 31, 2014	20,695,310	$38.76

The number of stock options vested, and expected to vest in the future, as of December 31, 2014 was not significantly different from the number of stock options outstanding at December 31, 2014 as stated above. As of December 31, 2014, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately seven years and six years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $342 million and $214 million, respectively.

As of December 31, 2014, there was $10 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 16 months.

For the years ended December 31, 2014, 2013, and 2012, total compensation cost for stock option awards recognized in income was $27 million, $25 million, and $23 million, respectively, with the related tax benefit also recognized in income of $10 million, $10 million, and $9 million, respectively.

The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $125 million, $77 million, and $162 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $48 million, $30 million, and $62 million for the years ended December 31, 2014, 2013, and 2012, respectively.

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, 2014, 2013, and 2012 was $400 million, $204 million, and $397 million, respectively.

Performance Shares

Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company’s total shareholder return (TSR) over the three-year performance period which measures Southern Company’s relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company’s actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control.

The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company’s stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company’s stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.

The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:

Year Ended December 31	2014	2013	2012
Expected volatility	12.6%	12.0%	16.0%
Expected term (in years)	3	3	3
Interest rate	0.6%	0.4%	0.4%
Annualized dividend rate	$2.03	$1.96	$1.89
Weighted average grant-date fair value	$37.54	$40.50	$41.99

  SOUTHERN COMPANYD-89

NOTES (continued)

Total unvested performance share units outstanding as of December 31, 2013 were 1,643,759. During 2014, 1,057,813 performance share units were granted, 755,716 performance share units were vested, and 115,475 performance share units were forfeited, resulting in 1,830,381 unvested units outstanding at December 31, 2014. In January 2015, the vested performance share award units were converted into 105,783 shares outstanding at a share price of $49.71 for the three-year performance and vesting period ended December 31, 2014.

For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $33 million, $31 million, and $28 million, respectively, with the related tax benefit also recognized in income of $13 million, $12 million, and $11 million, respectively. As of December 31, 2014, there was $37 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months.

Diluted Earnings Per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Average Common Stock Shares
	2014		2013		2012
	(in millions)
As reported shares		897		877		871
Effect of options and performance share award units		4		4		8
Diluted shares		901		881		879

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were $7 million and $16 million as of December 31, 2014 and 2013, respectively.

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2014, consolidated retained earnings included $6.4 billion of undistributed retained earnings of the subsidiaries.

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 $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 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 in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, 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 September 10, 2018. See Note 4 herein for additional information on joint ownership agreements.

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 $1.5 billion for members’ operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.

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

D-90  SOUTHERN COMPANY

NOTES (continued)

A builders’ risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction.

Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $50 million and $72 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 debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company’s financial condition and results of operations.

All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. FAIR VALUE MEASUREMENTS

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

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

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

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

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

  SOUTHERN COMPANYD-91

NOTES (continued)

As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of December 31, 2014:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Assets:
Energy-related derivatives	$	—	$	13	$	—	$	13
Interest rate derivatives		—		8		—		8
Nuclear decommissioning trusts:(a)
Domestic equity		583		85		—		668
Foreign equity		34		184		—		218
U.S. Treasury and government agency securities		—		130		—		130
Municipal bonds		—		62		—		62
Corporate bonds		—		299		—		299
Mortgage and asset backed securities		—		139		—		139
Other		11		13		3		27
Cash equivalents		397		—		—		397
Other investments		9		—		1		10
Total	$	1,034	$	933	$	4	$	1,971
Liabilities:
Energy-related derivatives	$	—	$	201	$	—	$	201
Interest rate derivatives		—		24		—		24
Total	$	—	$	225	$	—	$	225

(a) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information.

D-92  SOUTHERN COMPANY

NOTES (continued)

As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Assets:
Energy-related derivatives	$	—	$	24	$	—	$	24
Interest rate derivatives		—		3		—		3
Nuclear decommissioning trusts:(a)
Domestic equity		589		75		—		664
Foreign equity		35		196		—		231
U.S. Treasury and government agency securities		—		103		—		103
Municipal bonds		—		64		—		64
Corporate bonds		—		229		—		229
Mortgage and asset backed securities		—		132		—		132
Other		—		37		3		40
Cash equivalents		491		—		—		491
Other investments		9		—		4		13
Total	$	1,124	$	863	$	7	$	1,994
Liabilities:
Energy-related derivatives	$	—	$	56	$	—	$	56

(a) Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under “Nuclear Decommissioning” for additional information.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities’ individual prices from the primary pricing source.

A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts’ judgment, are also obtained when available.

Investments in private equity and real estate within the nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

“Other investments” include investments that are not traded in the open market. The fair value of these investment have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

  SOUTHERN COMPANYD-93

NOTES (continued)

As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

	Fair Value			Unfunded Commitments	Redemption Frequency	Redemption Notice Period
As of December 31, 2014:		(in millions	)
Nuclear decommissioning trusts:
Foreign equity funds	$	121		None	Monthly	5 days
Equity – commingled funds		63		None	Daily/Monthly	Daily/7 days
Debt – commingled funds		15		None	Daily	5 days
Other – commingled funds		8		None	Daily	Not applicable
Other – money market funds		11		None	Daily	Not applicable
Trust-owned life insurance		115		None	Daily	15 days
Cash equivalents:
Money market funds		397		None	Daily	Not applicable
As of December 31, 2013:
Nuclear decommissioning trusts:
Foreign equity funds	$	131		None	Monthly	5 days
Corporate bonds – commingled funds		8		None	Daily	Not applicable
Equity – commingled funds		65		None	Daily/Monthly	Daily/7 days
Other – commingled funds		24		None	Daily	Not applicable
Trust-owned life insurance		110		None	Daily	15 days
Cash equivalents:
Money market funds		491		None	Daily	Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have the Funds to comply with the NRC’s regulations. The foreign equity fund in Georgia Power’s nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts, including American depositary receipts, European depositary receipts, and global depositary receipts; and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund’s board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

The other-commingled funds and other-money market funds in Georgia Power’s nuclear decommissioning trusts are invested primarily in a diversified portfolio of high quality, short-term, liquid debt securities. The funds represent the cash collateral received under the Funds’ managers’ securities lending program and/or the excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the funds. See Note 1 under “Nuclear Decommissioning” for additional information.

Alabama Power’s nuclear decommissioning trusts include investments in TOLI. The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power’s nuclear

D-94  SOUTHERN COMPANY

NOTES (continued)

decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 under “Nuclear Decommissioning” for additional information.

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

As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
2014	$	24,015	$	25,816
2013	$	21,650	$	22,197

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

11. DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their 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 from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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

  SOUTHERN COMPANYD-95

NOTES (continued)

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

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

• Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions totaled 244 million mmBtu for the Southern Company system, with the longest hedge date of 2019 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2017 for derivatives not designated as hedges.

In addition to the volumes discussed above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 6 million mmBtu.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2015 are immaterial for Southern Company.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

D-96  SOUTHERN COMPANY

NOTES (continued)

At December 31, 2014, the following interest rate derivatives were outstanding:

	Notional Amount	Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) December 31, 2014
	(in millions)				(in millions)
Cash Flow Hedges of Forecasted Debt
	$200	3-month LIBOR	2.93%	October 2025	$            (8)
	350	3-month LIBOR	2.57%	May 2025	(6)
	350	3-month LIBOR	2.57%	November 2025	(2)
Cash Flow Hedges of Existing Debt
	250	3-month LIBOR + 0.32%	0.75%	March 2016	—
	200	3-month LIBOR + 0.40%	1.01%	August 2016	—
Fair Value Hedges of Existing Debt
	250	1.30%	3-month LIBOR + 0.17%	August 2017	1
	250	5.40%	3-month LIBOR + 4.02%	June 2018	(1)
	200	4.25%	3-month LIBOR + 2.46%	December 2019	—
Total	$2,050				$          (16)

The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2015 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and the hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. At December 31, 2014, there were no foreign currency derivatives outstanding.

  SOUTHERN COMPANYD-97

NOTES (continued)

Derivative Financial Statement Presentation and Amounts

At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

	Asset Derivatives					Liability Derivatives
Derivative Category	Balance Sheet Location	2014		2013		Balance Sheet Location	2014		2013
		(in millions)					(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:	Other current assets	$	7	$	16	Other current liabilities	$	118	$	26
	Other deferred charges and assets		—		7	Other deferred credits and liabilities		79		29
Total derivatives designated as hedging instruments for regulatory purposes		$	7	$	23		$	197	$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:	Other current assets	$	7	$	3	Other current liabilities	$	17	$	—
	Other deferred charges and assets		1		—	Other deferred credits and liabilities		7		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges		$	8	$	3		$	24	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives	Other current assets	$	6	$	—	Other current liabilities	$	4	$	1
	Other deferred charges and assets		—		1	Other deferred credits and liabilities		—		—
Total derivatives not designated as hedging instruments		$	6	$	1		$	4	$	1
Total		$	21	$	27		$	225	$	56

D-98  SOUTHERN COMPANY

NOTES (continued)

The Company’s derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company’s financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2014 and 2013 are presented in the following tables.

Fair Value
Assets	2014			2013			Liabilities	2014			2013
	(in millions)							(in millions)
Energy-related derivatives presented in the Balance Sheet (a)	$	13		$	24		Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	56
Gross amounts not offset in the Balance Sheet (b)		(9	)		(22	)	Gross amounts not offset in the Balance Sheet (b)		(9	)		(22	)
Net energy-related derivative assets	$	4		$	2		Net energy-related derivative liabilities	$	192		$	34
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	3		Interest rate derivatives presented in the Balance Sheet (a)	$	24		$	—
Gross amounts not offset in the Balance Sheet (b)		(8	)		—		Gross amounts not offset in the Balance Sheet (b)		(8	)		—
Net interest rate derivative assets	$	—		$	3		Net interest rate derivative liabilities	$	16		$	—

(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

	Unrealized Losses					Unrealized Gains
Derivative Category	Balance Sheet Location	2014		2013		Balance Sheet Location	2014		2013
		(in millions)					(in millions)
Energy-related   derivatives:	Other regulatory assets, current		$    (118)	$	(26)	Other regulatory liabilities, current	$	7	$	16
	Other regulatory assets, deferred		(79)		(29)	Other regulatory liabilities, deferred		—		7
Total energy-related derivative gains (losses)			$(197)		$(55)		$	7	$	23

For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for Southern Company. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company’s statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.

For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from OCI into earnings were immaterial for Southern Company.

There was no material ineffectiveness recorded in earnings for any period presented.

For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company.

For the Southern Company system’s energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in the Company’s statements of income for the years ended December 31, 2014, 2013, and 2012. This third party hedging activity has been discontinued.

  SOUTHERN COMPANYD-99

NOTES (continued)

Contingent Features

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2014, Southern Company’s collateral posted with its derivative counterparties was immaterial.

At December 31, 2014, the fair value of derivative liabilities with contingent features was $54 million. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties’ nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company’s, the traditional operating companies’, and Southern Power’s exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

12. SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company’s reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $383 million, $346 million, and $425 million in 2014, 2013, and 2012, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2014, 2013, and 2012 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power			Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
2014
Operating revenues	$	17,354	$	1,501		$	(449	)	$	18,406	$	159		$	(98	)	$	18,467
Depreciation and amortization		1,709		220			—			1,929		16			—			1,945
Interest income		17		1			—			18		3			(2	)		19
Interest expense		705		89			—			794		43			(2	)		835
Income taxes		1,056		(3	)		—			1,053		(76	)		—			977
Segment net income (loss)(a) (b)		1,797		172			—			1,969		(3	)		(3	)		1,963
Total assets		64,644		5,550			(131	)		70,063		1,156			(296	)		70,923
Gross property additions		5,568		942			—			6,510		11			1			6,522
2013
Operating revenues	$	16,136	$	1,275		$	(376	)	$	17,035	$	139		$	(87	)	$	17,087
Depreciation and amortization		1,711		175			—			1,886		15			—			1,901
Interest income		17		1			—			18		2			(1	)		19
Interest expense		714		74			—			788		36			—			824
Income taxes		889		46			—			935		(85	)		(1	)		849
Segment net income (loss)(a) (b)		1,486		166			—			1,652		(10	)		2			1,644
Total assets		59,447		4,429			(101	)		63,775		1,077			(306	)		64,546
Gross property additions		5,226		633			—			5,859		9			—			5,868

D-100  SOUTHERN COMPANY

NOTES (continued)

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
2012
Operating revenues	$	15,730	$	1,186	$	(438	)	$	16,478	$	141		$	(82	)	$	16,537
Depreciation and amortization		1,629		143		—			1,772		15			—			1,787
Interest income		21		1		—			22		19			(1	)		40
Interest expense		757		63		—			820		39			—			859
Income taxes		1,307		93		—			1,400		(66	)		—			1,334
Segment net income (loss)(a)		2,145		175		1			2,321		33			(4	)		2,350
Total assets		58,600		3,780		(129	)		62,251		1,116			(218	)		63,149
Gross property additions		4,813		241		—			5,054		5			—			5,059

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under “Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate” for additional information.

Products and Services

Electric Utilities’ Revenues
Year	Retail	Wholesale	Other	Total
	(in millions)
2014	$15,550	$2,184	$672	$18,406
2013	14,541	1,855	639	17,035
2012	14,187	1,675	616	16,478

  SOUTHERN COMPANYD-101

NOTES (continued)

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2014 and 2013 is as follows:

Quarter Ended	Operating Revenues		Operating Income		Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries		Per Common Share
													Trading Price Range
							Basic Earnings		Diluted Earnings		Dividends		High		Low
			(in millions)
March 2014	$	4,644	$	700	$	351	$	0.39	$	0.39	$	0.5075	$	44.00	$	40.27
June 2014		4,467		1,103		611		0.68		0.68		0.5250		46.81		42.55
September 2014		5,339		1,278		718		0.80		0.80		0.5250		45.47		41.87
December 2014		4,017		561		283		0.31		0.31		0.5250		51.28		43.55
March 2013	$	3,897	$	325	$	81	$	0.09	$	0.09	$	0.4900	$	46.95	$	42.82
June 2013		4,246		640		297		0.34		0.34		0.5075		48.74		42.32
September 2013		5,017		1,491		852		0.97		0.97		0.5075		45.75		40.63
December 2013		3,927		799		414		0.47		0.47		0.5075		42.94		40.03

As a result of the revisions to the cost estimate for the Kemper IGCC, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $70.0 million ($43.2 million after tax) in the fourth quarter 2014, $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $540.0 million ($333.5 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.05 billion ($1.26 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through December 31, 2014. See Note 3 under “Integrated Coal Gasification Combined Cycle” for additional information.

The Southern Company system’s business is influenced by seasonal weather conditions.

D-102  SOUTHERN COMPANY

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

For the Periods Ended December 2010 through 2014

Southern Company and Subsidiary Companies 2014 Annual Report

	2014		2013		2012		2011		2010
Operating Revenues (in millions)	$	18,467	$	17,087	$	16,537	$	17,657	$	17,456
Total Assets (in millions)	$	70,923	$	64,546	$	63,149	$	59,267	$	55,032
Gross Property Additions (in millions)	$	6,522	$	5,868	$	5,059	$	4,853	$	4,443
Return on Average Common Equity (percent)		10.08		8.82		13.10		13.04		12.71
Cash Dividends Paid Per Share of Common Stock	$	2.0825	$	2.0125	$	1.9425	$	1.8725	$	1.8025
Consolidated Net Income After Preferred and Preference Stock of Subsidiaries (in millions)	$	1,963	$	1,644	$	2,350	$	2,203	$	1,975
Earnings Per Share —
Basic	$	2.19	$	1.88	$	2.70	$	2.57	$	2.37
Diluted		2.18		1.87		2.67		2.55		2.36
Capitalization (in millions):
Common stock equity	$	19,949	$	19,008	$	18,297	$	17,578	$	16,202
Preferred and preference stock of subsidiaries and noncontrolling interest		977		756		707		707		707
Redeemable preferred stock of subsidiaries		375		375		375		375		375
Redeemable noncontrolling interest		39		—		—		—		—
Long-term debt		20,841		21,344		19,274		18,647		18,154
Total (excluding amounts due within one year)	$	42,181	$	41,483	$	38,653	$	37,307	$	35,438
Capitalization Ratios (percent):
Common stock equity		47.3		45.8		47.3		47.1		45.7
Preferred and preference stock of subsidiaries and noncontrolling interest		2.3		1.8		1.8		1.9		2.0
Redeemable preferred stock of subsidiaries		0.9		0.9		1.0		1.0		1.1
Redeemable noncontrolling interest		0.1		—		—		—		—
Long-term debt		49.4		51.5		49.9		50.0		51.2
Total (excluding amounts due within one year)		100.0		100.0		100.0		100.0		100.0
Other Common Stock Data:
Book value per share	$	21.98	$	21.43	$	21.09	$	20.32	$	19.21
Market price per share:
High	$	51.28	$	48.74	$	48.59	$	46.69	$	38.62
Low		43.55		40.03		41.75		35.73		30.85
Close (year-end)		49.11		41.11		42.81		46.29		38.23
Market-to-book ratio (year-end) (percent)		223.4		191.8		203.0		227.8		199.0
Price-earnings ratio (year-end) (times)		22.4		21.9		15.9		18.0		16.1
Dividends paid (in millions)	$	1,866	$	1,762	$	1,693	$	1,601	$	1,496
Dividend yield (year-end) (percent)		4.2		4.9		4.5		4.0		4.7
Dividend payout ratio (percent)		95.0		107.1		72.0		72.7		75.7
Shares outstanding (in thousands):
Average		897,194		876,755		871,388		856,898		832,189
Year-end		907,777		887,086		867,768		865,125		843,340
Stockholders of record (year-end)		137,369		143,800		149,628		155,198		160,426
Traditional Operating Company Customers (year-end) (in thousands):
Residential		3,890		3,859		3,832		3,809		3,813
Commercial*		587		582		579		578		579
Industrial*		16		16		16		16		15
Other		11		10		9		9		10
Total		4,504		4,467		4,436		4,412		4,417
Employees (year-end)		26,369		26,300		26,439		26,377		25,940

* A reclassification of customers from commercial to industrial is reflected for years 2010-2013 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

  SOUTHERN COMPANYD-103

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)

For the Periods Ended December 2010 through 2014

Southern Company and Subsidiary Companies 2014 Annual Report

	2014		2013		2012		2011		2010
Operating Revenues (in millions):
Residential	$	6,499	$	6,011	$	5,891	$	6,268	$	6,319
Commercial		5,469		5,214		5,097		5,384		5,252
Industrial		3,449		3,188		3,071		3,287		3,097
Other		133		128		128		132		123
Total retail		15,550		14,541		14,187		15,071		14,791
Wholesale		2,184		1,855		1,675		1,905		1,994
Total revenues from sales of electricity		17,734		16,396		15,862		16,976		16,785
Other revenues		733		691		675		681		671
Total	$	18,467	$	17,087	$	16,537	$	17,657	$	17,456
Kilowatt-Hour Sales (in millions):
Residential		53,347		50,575		50,454		53,341		57,798
Commercial		53,243		52,551		53,007		53,855		55,492
Industrial		54,140		52,429		51,674		51,570		49,984
Other		909		902		919		936		943
Total retail		161,639		156,457		156,054		159,702		164,217
Wholesale sales		32,786		26,944		27,563		30,345		32,570
Total		194,425		183,401		183,617		190,047		196,787
Average Revenue Per Kilowatt-Hour (cents):
Residential		12.18		11.89		11.68		11.75		10.93
Commercial		10.27		9.92		9.62		10.00		9.46
Industrial		6.37		6.08		5.94		6.37		6.20
Total retail		9.62		9.29		9.09		9.44		9.01
Wholesale		6.66		6.88		6.08		6.28		6.12
Total sales		9.12		8.94		8.64		8.93		8.53
Average Annual Kilowatt-Hour
Use Per Residential Customer		13,765		13,144		13,187		13,997		15,176
Average Annual Revenue
Per Residential Customer	$	1,679	$	1,562	$	1,540	$	1,645	$	1,659
Plant Nameplate Capacity
Ratings (year-end) (megawatts)		46,549		45,502		45,740		43,555		42,961
Maximum Peak-Hour Demand (megawatts):
Winter		37,234		27,555		31,705		34,617		35,593
Summer		35,396		33,557		35,479		36,956		36,321
System Reserve Margin (at peak) (percent)*		19.8		21.5		20.8		19.2		23.3
Annual Load Factor (percent)		59.6		63.2		59.5		59.0		62.2
Plant Availability (percent)**:
Fossil-steam		85.8		87.7		89.4		88.1		91.4
Nuclear		91.5		91.5		94.2		93.0		92.1
Source of Energy Supply (percent):
Coal		39.3		36.9		35.2		48.7		55.0
Nuclear		14.8		15.5		16.2		15.0		14.1
Hydro		2.5		3.9		1.7		2.1		2.5
Oil and gas		37.4		37.3		38.3		28.0		23.7
Purchased power		6.0		6.4		8.6		6.2		4.7
Total		100.0		100.0		100.0		100.0		100.0

* Beginning in 2014, system reserve margin is calculated to include unrecognized capacity.

** Beginning in 2012, plant availability is calculated as a weighted equivalent availability.

D-104  SOUTHERN COMPANY

MANAGEMENT COUNCIL

1. THOMAS A. FANNING

Chairman, President, and Chief Executive Officer

Fanning, 58, joined the Company as a Financial Analyst in 1980. He has held his current position since December 2010. Previously, Fanning served as Executive Vice President and Chief Operating Officer of the Company, President and Chief Executive Officer of Gulf Power, and Chief Financial Officer of the Company, Georgia Power, and Mississippi Power.

2. ART P. BEATTIE

Executive Vice President and Chief Financial Officer

Beattie, 60, joined the Company in 1976 as a Junior Accountant with Alabama Power. He has held his current position since August 2010. Beattie is responsible for the Company’s accounting, finance, tax, investor relations, treasury, and risk management functions. He also serves as Chief Risk Officer. Previously, Beattie served in several executive accounting and finance positions at Alabama Power, including Chief Financial Officer, Treasurer, and Comptroller.

3. W. PAUL BOWERS

Executive Vice President and Chairman, President, and Chief Executive Officer of Georgia Power

Bowers, 58, joined the Company as a Residential Sales Representative with Gulf Power in 1979. He has held his current position since January 2011. Previously, Bowers served as Chief Operating Officer of Georgia Power. He also served as Chief Financial Officer of the Company, President of Southern Company Generation, President and Chief Executive Officer of Southern Power, President and Chief Executive Officer of the Company’s former United Kingdom subsidiary, and Senior Vice President and Chief Marketing Officer of the Company.

4. S. W. CONNALLY, JR.

President and Chief Executive Officer of Gulf Power

Connally, 45, joined the Company in 1989 as a Co-Op Student at Georgia Power. He has held his current position since July 2012. Previously, he served as Senior Vice President and Senior Production Officer for Georgia Power. He has served as Plant Manager at Plants Watson, Daniel, and Barry. He has also worked in Customer Operations and Sales and Marketing.

5. MARK A. CROSSWHITE

Executive Vice President and Chairman, President, and Chief Executive Officer of Alabama Power

Crosswhite, 52, joined the Company in 2004 as Senior Vice President and General Counsel for Southern Company Generation. He has held his current position since March 2014. He was previously Executive Vice President and Chief Operating Officer of the Company, President and Chief Executive Officer of Gulf Power, and Executive Vice President of External Affairs and Senior Vice President and General Counsel at Alabama Power. Prior to joining the Company, he was a partner in the law firm of Balch & Bingham LLP in Birmingham, Alabama, where he practiced for 17 years.

6. KIMBERLY S. GREENE

Executive Vice President and Chief Operating Officer

Greene, 48, has held her current position since March 2014. Previously, she was President and Chief Executive Officer of Southern Company Services, Inc. Prior to that, she was employed by Tennessee Valley Authority (TVA), where she served as Chief Financial Officer, Group President of Strategy and External Relations, and Chief Generation Officer. Prior to her time at TVA, she served as Senior Vice President of Finance and Treasurer for the Company and has held various positions with Mirant Corporation, including Chief Commercial Officer, South Region.

7. G. EDISON HOLLAND, JR.

Executive Vice President and Chairman, President, and Chief Executive Officer of Mississippi Power

Holland, 62, joined the Company as Vice President and Corporate Counsel for Gulf Power in 1992. He was named to his current position in May 2013. Previously, he was Executive Vice President, General Counsel, and Corporate Secretary of the Company, President and Chief Executive Officer of Savannah Electric and Power Company, and Vice President of Power Generation and Transmission at Gulf Power.

8. JAMES Y. KERR II

Executive Vice President and General Counsel

Kerr, 51, assumed his current role in March 2014. Previously, he was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC. He also served as co-chairman of the McGuireWoods energy industry team with focus in the areas of energy transactions and finance, energy regulation, energy policy, and energy litigation. Prior to joining McGuireWoods, Kerr served as a Commissioner on the North Carolina Utilities Commission and was the former President of the National Association of Regulatory Utility Commissioners.

  SOUTHERN COMPANYD-105

9. STEPHEN E. KUCZYNSKI

Chairman, President, and Chief Executive Officer of Southern Nuclear

Kuczynski, 52, joined the Company in July 2011 as President and Chief Executive Officer of Southern Nuclear. Previously, he served as Senior Vice President of Engineering and Technical Services of Exelon Nuclear. He also served as Senior Vice President of Exelon Nuclear’s Midwest operations, Senior Vice President of Operations Support, and Plant Manager and later Site Vice President for Exelon’s Byron Nuclear Station.

10. MARK S. LANTRIP

Executive Vice President and Chairman, President, and Chief Executive Officer, Southern Company Services, Inc.

Lantrip, 60, joined the Company in 1981 as an analyst in Gulf Power’s Corporate Planning department. He assumed his current position in March 2014. Previously, Lantrip was Executive Vice President of Finance and Treasurer of Southern Company Services, Inc. and Treasurer of the Company, with responsibility for financial planning and analysis, enterprise risk management, trust finance, capital markets, and treasury.

11. CHRISTOPHER C. WOMACK

Executive Vice President and President of External Affairs

Womack, 57, joined the Company in 1988 as a Governmental Affairs Representative for Alabama Power. He has held his current position since January 2009. Previously, Womack was Executive Vice President of External Affairs for Georgia Power. He has also served as Senior Vice President of Human Resources and Chief People Officer for the Company, as well as Senior Vice President and Senior Production Officer of Southern Company Generation.

Biographical information for the Board of Directors is set forth on pages 1 through 8 of the attached Proxy Statement.

D-106  SOUTHERN COMPANY

STOCKHOLDER INFORMATION

Transfer Agent

Computershare Inc. (Computershare) is Southern Company’s transfer agent, dividend-paying agent, investment plan administrator, and registrar. If you have questions concerning your registered shareowner account, please contact:

By Mail

Computershare

P.O. Box 30170

College Station, TX 77842-3170

By Courier

Computershare

211 Quality Circle

Suite 210

College Station, TX 77845

By Phone-United States

9 a.m. to 7 p.m. ET

Monday through Friday

800-554-7626

(Automated voice response system 24 hours/day, 7 days/week)

Hearing Impaired: 800-231-5469

By Phone-Outside United States

201-680-6693

Shareowner Services Internet Site

To take advantage of Computershare’s online services, you will need to activate your account. This one-time authentication process will be used to validate your identity in addition to your 12-digit Investor ID and your Computershare Holder ID. The internet address is www.computershare.com/investor. Through this site, registered shareowners can securely access their account information, as well as submit numerous transactions. Also, transfer instructions and service request forms can be obtained.

Southern Investment Plan

The Southern Investment Plan provides a convenient way to purchase common stock and reinvest dividends. You can access the Southern Company internet site to review the prospectus.

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 2014 is taxable. The Board of Directors sets the record and payment dates for quarterly dividends. A dividend of 52.50 cents per share was paid in March 2015. For the remainder of 2015, projected record dates are May 18, August 17, and November 16. Projected payment dates for dividends declared during the remainder of 2015 are June 6, September 5, and December 5.

Auditors

Deloitte & Touche LLP

191 Peachtree St. NE

Suite 2000

Atlanta, GA 30303

During 2014, there were no changes in or disagreements with the auditors on accounting and financial disclosure.

Investor Information Line

For information about earnings and dividends, stock quotes, and current news releases, please visit investor.southerncompany.com.

Institutional Investor Inquiries

Southern Company maintains an investor relations office in Atlanta, 404-506-5310, 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.

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/#reports.

To request printed materials, write to:

Larry Monroe

Chief Environmental Officer and Senior Vice President

Research and Environmental Affairs

600 North 18th St.

Bin 14N-8195

Birmingham, AL 35203-2206

Common Stock

Southern Company’s common stock is listed on the New York Stock Exchange under the ticker symbol SO. On January 31, 2015, Southern Company had 136,875 stockholders of record.

Principal Executive Office

Southern Company’s principal executive office is located at 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.

  SOUTHERN COMPANYD-107

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  C/O PROXY SERVICES P.O. BOX 9112 FARMINGDALE, NY 11735 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 until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your proxy card in hand when you access the website and follow the instructions to obtain your records and to create an electronic voting instruction form.   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 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 enclosed postage-paid envelope or return it to The Southern Company, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.   THANK YOU VIEW ANNUAL REPORT AND PROXY STATEMENT ON THE INTERNET www.southerncompany.com

TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK

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THIS PROXY CARD IS VALID ONLY WHEN SIGNED AND DATED.

THE SOUTHERN COMPANY

The Board of Directors recommends a vote FOR each nominee in Item 1.

1.

ELECTION OF DIRECTORS:

For

Against

Abstain

1a.

J. P. Baranco

¨

¨

¨

1b.

J. A. Boscia

¨

¨

¨

For

Against

Abstain

1c.

H. A. Clark III

¨

¨

¨

1m.

S. R. Specker

¨

¨

¨

1d.

T. A. Fanning

¨

¨

¨

1n.

L. D. Thompson

¨

¨

¨

1e.

D. J. Grain

¨

¨

¨

1o.

E. J. Wood III

¨

¨

¨

The Board of Directors recommends a vote FOR Items 2, 3, 4, and 5.

1f.

V. M. Hagen

¨

¨

¨

2.

APPROVAL OF THE OUTSIDE DIRECTORS STOCK PLAN

¨

¨

¨

1g.

W. A. Hood, Jr.

¨

¨

¨

3.

APPROVAL OF AN AMENDMENT TO THE BY-LAWS RELATED TO THE ABILITY OF STOCKHOLDERS TO ACT BY WRITTEN CONSENT TO AMEND THE BY-LAWS

¨

¨

¨

1h.

L. P. Hudson

¨

¨

¨

4.

ADVISORY VOTE TO APPROVE NAMED EXECUTIVE OFFICERS’ COMPENSATION

¨

¨

¨

1i.

D. M. James

¨

¨

¨

5.

RATIFICATION OF THE APPOINTMENT OF DELOITTE & TOUCHE LLP AS THE COMPANY’S INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2015

¨

¨

¨

1j.

J. D. Johns

¨

¨

¨

The Board of Directors recommends a vote AGAINST Items 6 and 7.

1k.

D. E. Klein

¨

¨

¨

6.

STOCKHOLDER PROPOSAL ON PROXY ACCESS

¨

¨

¨

1l.

W. G. Smith, Jr.

¨

¨

¨

7.

STOCKHOLDER PROPOSAL ON GREENHOUSE GAS EMISSIONS REDUCTION GOALS

¨

¨

¨

UNLESS OTHERWISE SPECIFIED ABOVE, THE SHARES WILL BE VOTED “FOR” ITEMS 1, 2, 3, 4, and 5 and “AGAINST” ITEMS 6 and 7. NOTE: The last instruction received in either paper or electronic form prior to the deadline will be the instruction included in the final tabulation.

Signature [PLEASE SIGN WITHIN BOX]

Date

Signature (Joint Owners)

Date

ADMISSION TICKET

(Not Transferable)

2015 Annual Meeting of Stockholders
10 a.m. ET, May 27, 2015
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 take 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 the Availability of Proxy Materials for the Annual Meeting:

The Notice and Proxy Statement with the 2014 Annual Report as an appendix are available at www.proxyvote.com.

M84920-P59459

FORM OF PROXY AND TRUSTEE VOTING INSTRUCTION FORM   FORM OF PROXY AND TRUSTEE VOTING INSTRUCTION FORM

PROXY SOLICITED ON BEHALF OF BOARD OF DIRECTORS AND ESP TRUSTEES

If a stockholder of record, the undersigned hereby appoints T. A. Fanning, A. P. Beattie, and J. Y. Kerr II, 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, 2015, 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 and 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 11:00 a.m. on Tuesday, May 26, 2015. The deadline for receipt of shares of record voted through the Form of Proxy is 9:00 a.m. on Wednesday, May 27, 2015. The deadline for receipt of instructions provided electronically is 11:59 p.m. on Tuesday, May 26, 2015.

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 AND 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.