DEF 14A
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
Filed by the
Registrant x
Filed by a Party other than the
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Preliminary Proxy Statement |
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Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e) (2)) |
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Definitive Proxy Statement |
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Definitive Additional Materials |
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Soliciting Materials Pursuant to §240.14a-12 |
THE SOUTHERN COMPANY
(Name of Registrant as Specified In Its Charter)
N/A
(Name of Person(s) Filing Proxy Statement, if other than Registrant)
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TABLE OF CONTENTS
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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 Companys audited financial statements and managements
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
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DATE: |
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Wednesday, May 27, 2015 |
TIME: |
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10:00 a.m., ET |
PLACE: |
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The Lodge Conference Center at Callaway Gardens Highway 18
Pine Mountain, Georgia 31822 |
DIRECTIONS: |
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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
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To elect 15 Directors; |
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To approve The Southern Company Outside Directors Stock Plan; |
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To approve an amendment to the By-Laws related to the ability of stockholders to act by written consent to amend the By-Laws;
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To approve on a non-binding advisory basis The Southern Companys named executive officers compensation; |
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To ratify the appointment of Deloitte & Touche LLP as The Southern Companys independent registered public accounting firm for 2015; |
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To consider a stockholder proposal on proxy access; |
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To consider a stockholder proposal on greenhouse gas emissions reduction goals; and |
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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 Companys 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.
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VOTE BY INTERNET
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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. |
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VOTE BY PHONE
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1-800-690-6903 |
Toll-free 24 hours a day/7 days a week |
Instructions: |
Read this Proxy Statement |
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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 Companys 2015 Proxy Statement, which
includes the 2014 Annual Report as an appendix, is also available free of charge on the Companys website at http://investor.southerncompany.com/proxy.
The Companys 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):
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The Boards 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 Companys industry and subsidiaries service territories. |
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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 Companys stockholders. |
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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
Companys 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. |
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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 Companys 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. |
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For |
Item 5. Ratification of Independent Auditor for 2015 (page 71)
The Audit Committee has appointed Deloitte & Touche LLP (Deloitte & Touche) as the Companys 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 Companys independent registered
public accounting firm is in the best interests of the Company and its stockholders. |
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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 proponents 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 Companys corporate governance. |
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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 systems 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 Companys current efforts in this area. |
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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.
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:
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Annual election of Directors |
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Majority voting for Directors, with a Director resignation policy |
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10% threshold for stockholders to request a special meeting |
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14 of 15 Directors are independent |
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Strong Lead Independent Director |
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Annual Board and committee self-evaluations |
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Proactive stockholder engagement |
RECENT GOVERNANCE ENHANCEMENTS
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Established Business Security Subcommittee of the Board
see page 20 |
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Increased Stakeholder Engagement Efforts
see page 12 |
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Added Former U.S. Deputy Attorney General Larry D. Thompson to the Board
see page 8 |
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Added Alabama Business and Civic Leader John D. Johns to the Board
see page 6 |
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Enhanced the Responsibilities of the Lead Independent Director
see page 15 |
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Refreshed the Composition of Key Board Committees...see pages 16 to 20 |
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.
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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. |
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Compensation and Benefit Beliefs and Practices
The Companys compensation and benefit program is based on the following beliefs:
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Employees commitment and performance have a significant impact on achieving business results; |
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Compensation and benefits offered must attract, retain, and engage employees and must be financially sustainable; |
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Compensation should be consistent with performance: higher pay for higher performance and lower pay for lower performance; and |
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Both business drivers and culture should influence the compensation and benefit program. |
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Based on these beliefs, the Compensation Committee believes that the Companys executive
compensation program should:
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Be competitive with the Companys industry peers; |
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Motivate and reward achievement of the Companys goals; |
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Be aligned with the interests of the Companys stockholders and its subsidiaries customers; and |
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Not encourage excessive risk-taking. |
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Executive compensation is targeted at the market median of industry peers, but actual compensation is
primarily determined by achievement of the Companys 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
Companys stockholders. Therefore, short-term performance pay is based on achievement of the Companys 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 DONT DO
No-hedging provision in insider trading policy
No excise tax gross-ups on change-in-control severance arrangements
Limited ongoing perquisites
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 Companys industry and subsidiaries service territories, as detailed below.
Juanita Powell Baranco
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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) |
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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.
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The Board has benefited from Ms. Barancos particular expertise in business operations and her civic involvement. |
Jon A. Boscia
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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) |
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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 companys 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. |
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Mr. Boscias extensive background in finance, investment management, information technology, and corporate governance are valuable to the Board. |
Henry A. Hal Clark III
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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 |
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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.
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Mr. Clarks utility global financial and utility industry expertise as well as his expertise in capital market transactions are valuable to the
Board. |
Thomas A. Fanning
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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
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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 Companys generation and transmission, engineering, and construction
services, research and environmental affairs, system planning, and competitive generation business units. He served as the Companys 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 Companys 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.
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Mr. Fannings knowledge of the Companys 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
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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 |
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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 countrys
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 Broadbands 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.
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Mr. Grains background in finance, investment management, and wireless communications infrastructure, leadership, and civic involvement are valuable to the
Board. |
Veronica M. Hagen
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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 |
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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.
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Ms. Hagens global operational management experience and commercial business leadership are valuable assets to the Board. |
Warren A. Hood, Jr.
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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) |
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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 Companys 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 Bryants
Mississippi Works Committee, and The Governors 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.
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Mr. Hoods business operations, risk management, and financial experience and civic involvement are valuable to the Board. |
Linda P. Hudson
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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 |
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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 worlds 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 Corporations 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. |
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Ms. Hudsons 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
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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) |
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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 Childrens of Alabama, where he serves on the Executive Committee. In addition, he serves on the Finance and the Human
Resources Committees of Wells Fargo & Companys Board of Directors. |
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Mr. James leadership of a large public company, his legal expertise, and his civic involvement are valuable assets to the Board. |
John D. Johns
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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) |
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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, Alabamas leading business and
technology incubator. |
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Mr. Johns management and leadership experience, his significant familiarity with Alabama Power, and his civic involvement are valuable to the
Board. |
Dale E. Klein
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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 |
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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 universitys 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 Corporations principal subsidiary, Arizona Public Service Company.
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Dr. Kleins expertise in nuclear energy regulation and operations, technology, and safety is valuable to the Board. |
William G. Smith, Jr.
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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. |
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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. |
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Mr. Smiths experience in finance, business operations, and risk management is valuable to the Board. |
Steven R. Specker
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Age: 69
Director since: 2010
Board committees: Nuclear/Operations (Chair), Compensation and Management Succession
Other public company directorships: Trilliant
Incorporated |
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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 GEs 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.
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Dr. Specker brings to the Board a keen understanding of the electric industry and valuable insight in innovation and technology development. |
Larry D. Thompson
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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.) |
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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 worlds 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
companys 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 Justices 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. |
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Mr. Thompsons government experience and corporate governance and legal expertise are valuable to the Board. |
E. Jenner Wood III
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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) |
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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. |
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Mr. Woods leadership experience and extensive background in finance as well as his involvement in the community are beneficial to the Board. |
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.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR THE NOMINEES LISTED IN ITEM NO. 1. |
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ITEM NO. 2 APPROVAL
OF THE COMPANYS 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 Companys
stockholders.
The Plan will be administered by the Companys 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 Companys 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 Companys 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 Companys 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.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ITEM NO. 2. |
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ITEM NO. 3 AMENDMENT TO THE
COMPANYS 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
Companys 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
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 Companys 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
Companys Certificate of Incorporation permits the Companys 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 Companys 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 Companys 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 Companys Certificate of Incorporation to make clear that the standard set forth in Section 228(a) of the
DGCL governs the ability of the Companys 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.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ITEM NO. 3. |
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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 Companys website at
www.southerncompany.com under Information for Investors/Corporate Governance.
Corporate Governance Website
In addition to the Companys Corporate Governance Guidelines (which include Board independence criteria), other information relating to corporate governance of the
Company is available on the Companys Corporate Governance webpage at www.southerncompany.com under Information for Investors/Corporate Governance.
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Executive Stock Ownership Requirements |
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Board Committee Charters |
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Board of Directors Background and Experience |
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Management Council Background and Experience |
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Composition of Board Committees |
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Link for on-line communication with Board of Directors |
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Political Spending and Lobbying-Related Activities |
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:
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The Director was employed by the Company or the Directors immediate family member was an executive officer of the Company.
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The Director has received, or the Directors 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.) |
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The Director was affiliated with or employed by, or the Directors 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 Companys audit. |
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The Director was employed, or the Directors immediate family member was employed, as an executive officer of a company where any member of the Companys present executive officers at the same time served on
that companys compensation committee. |
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The Director is a current employee, or the Directors 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 companys consolidated gross revenues. |
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The Director or the Directors 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 organizations 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 Directors 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
the Companys 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 Companys 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 systems 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 Companys Board or specified Directors, including the Lead Independent Director.
Communications may be sent to the Companys 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 Companys 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 systems 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 Companys 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
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 Companys 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:
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Additional $20,000 cash retainer if serving as a chair of a committee of the Board |
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Additional $20,000 cash retainer if serving as the Lead Independent Director of the Board |
Annual equity grant:
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$120,000 in deferred Common Stock units until Board membership ends |
Meeting fees:
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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. |
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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.
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 Directors election:
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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 |
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at the prime interest rate which is paid in cash upon leaving the Board.
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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 Companys 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.
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Name |
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Fees Earned or Paid in
Cash ($) (1) |
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Stock Awards ($)
(2) |
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Option Awards ($)
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Non-Equity Incentive
Plan Compensation ($) |
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Change in Pension
Value and Nonqualified Deferred Compensation Earnings ($) |
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All Other Compensation ($)
(3) |
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Total ($)
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Juanita Powell Baranco |
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116,667 |
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120,000 |
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1,502 |
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238,169 |
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Jon A. Boscia |
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120,000 |
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120,000 |
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1,499 |
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241,499 |
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Henry A. Clark III |
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111,667 |
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120,000 |
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1,723 |
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233,390 |
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David J. Grain |
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100,001 |
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120,000 |
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1,310 |
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221,311 |
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H. William Habermeyer, Jr. (4) |
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50,000 |
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50,000 |
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|
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|
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280 |
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100,280 |
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Veronica M. Hagen |
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120,000 |
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120,000 |
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1,453 |
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241,453 |
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Warren A. Hood, Jr. |
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100,001 |
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120,000 |
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1,443 |
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221,444 |
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Linda P. Hudson (5) |
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75,001 |
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90,000 |
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1,301 |
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166,302 |
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Donald M. James |
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111,667 |
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120,000 |
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1,647 |
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233,314 |
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Dale E. Klein |
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100,001 |
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120,000 |
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1,175 |
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221,176 |
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William G. Smith, Jr. |
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120,000 |
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120,000 |
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1,175 |
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241,175 |
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Steven R. Specker |
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111,667 |
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120,000 |
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1,559 |
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233,226 |
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Larry D. Thompson (6) |
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8,333 |
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10,000 |
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1,077 |
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19,410 |
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E. Jenner Wood
III |
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100,001 |
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120,000 |
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1,675 |
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221,676 |
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(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. |
Director Stock Ownership Guidelines
Under the Companys 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 Companys 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 Companys 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 Companys 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:
|
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approving the agenda and schedule for Board meetings and information sent to the Board; |
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calling and chairing executive sessions of the non-management Directors; |
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chairing Board meetings in the absence of the Chairman; |
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meeting regularly with the Chairman; |
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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); |
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serving as the primary contact Director for stockholders and other interested parties; and |
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communicating any sensitive issues to the Directors. |
Ms. Veronica M. Hagen currently serves as the
Companys Lead Independent Director. Mr. William G. Smith, Jr. served as the Companys 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 Companys 2016 Annual Meeting of Stockholders. On July 21, 2014, the Board of Directors approved an amendment to the Companys Corporate Governance Guidelines changing the Presiding
Directors title to Lead Independent Director and enhancing the Lead Independent Directors responsibilities, including noting that the Lead Independent Director
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 Companys 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
Companys website www.southerncompany.com under Information for Investors/Corporate Governance.
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Jon A. Boscia Chair |
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Current members are Mr. Boscia (Chair), Ms. Baranco,(1) Mr. Hood, Mr. Johns,(2) and
Mr. Thompson.(1) |
Ø |
The Audit Committees duties and responsibilities, which are described in its charter, include the following: |
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Oversee the Companys financial reporting, audit processes, internal controls, and legal, regulatory, and ethical compliance. |
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Appoint the Companys independent registered public accounting firm, approve its services and fees, and establish and review the scope and timing of its audits. |
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Review and discuss the Companys financial statements with management, the internal auditors, and the independent registered public accounting firm, including critical accounting policies and practices,
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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.
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Recommend the filing of the Companys and its registrant subsidiaries annual financial statements with the SEC.
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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. |
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Compensation and Management Succession Committee (Compensation Committee) |
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Henry A. Hal Clark III
Chair |
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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 Committees duties and responsibilities, which are described in its charter, include the following: |
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Evaluate performance of executive officers and establish their compensation, administer executive compensation plans, and review management succession plans.
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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 Companys subsidiaries.
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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 Committees 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; |
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Receiving meeting materials several days in advance of meetings; |
¡ |
Having regular executive sessions of Compensation Committee members only; |
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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 Companys goal-setting process; and
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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 Companys 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
Companys 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 Companys 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
work with Company management to ensure that the executive compensation program is designed and administered consistent with the Compensation Committees 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 Governances
independence including (1) the amount of fees received by Pay Governance from the Company as a percentage of Pay Governances 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.
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William G. Smith, Jr.
Chair |
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Current members are Mr. Smith (Chair), Mr. Clark, Mr. Grain,(1) and Mr. James |
Ø |
Met seven times in 2014 |
Ø |
The Finance Committees duties and responsibilities, which are described in its charter, include the following: |
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Review the Companys financial matters and recommend actions such as dividend philosophy and financial plan approval to the Board. |
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Provide input to the Compensation Committee regarding the Companys financial plan and associated financial goals.
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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. |
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Donald M. James
Chair |
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Current members are Mr. James (Chair), Ms. Hudson,(1) Dr. Klein, and Mr. Wood |
Ø |
The Governance Committees duties and responsibilities, which are described in its charter, include the following: |
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Recommend Board size and membership criteria and identify, evaluate, and recommend Director candidates. |
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Oversee and make recommendations regarding the composition of the Board and its committees. |
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Review and make recommendations regarding total compensation for non-employee Directors. |
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Periodically review and recommend updates to the Corporate Governance Guidelines and Board committee charters. |
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Coordinate the performance evaluations of the Board and its committees. |
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Review stock ownership of non-employee Directors annually to ensure compliance with the Companys Director stock ownership guidelines.
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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 candidates qualifications, relevant biographical information, and signed consent to serve. These materials should be submitted in
writing to the Companys 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 Companys 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 Companys traditional operating subsidiaries, which are primarily in the
Southeastern United States. Accordingly, the Company uniquely benefits from the experience of Directors who have previously served on the boards of the Companys subsidiary companies. These
operating company boards provide an opportunity for Director candidates to cultivate significant relevant experience with the Companys business.
The
Governance Committee only considers candidates with the highest degree of integrity and ethical standards. The Governance Committee evaluates a candidates 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 Companys 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.
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Nuclear/Operations Committee |
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Steven R. Specker
Chair |
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Current members are Dr. Specker (Chair), Ms. Hagen, Ms. Hudson,(1) Dr. Klein, and Mr. Wood |
Ø |
The Nuclear/Operations Committees duties and responsibilities, which are described in its charter, include the following: |
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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. |
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Oversee the Southern Company systems management of significant construction projects. |
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Provide input to the Compensation Committee on the Southern Company systems key operational goals and metrics.
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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 Subcommittees responsibilities include
oversight of managements efforts to establish and continuously improve enterprise-wide security policies, programs, standards, and controls and oversight of managements efforts to
monitor significant security events and operational and compliance activities.
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 Companys 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 Companys 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 Companys 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 Companys 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.
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.
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Shares Beneficially Owned Include: |
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Directors, Nominees, and Executive
Officers |
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Shares Beneficially Owned (1)
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Deferred Common Stock Units (2)
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Shares Individuals Have Rights to Acquire
within 60 Days (3) |
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Shares Held by Family Member (4)
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Juanita Powell Baranco |
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70,407 |
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69,748 |
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Art P. Beattie |
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523,200 |
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507,587 |
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51 |
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Jon A. Boscia |
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80,918 |
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21,918 |
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W. Paul Bowers |
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1,169,695 |
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1,108,858 |
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Henry A. Clark III |
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15,587 |
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15,587 |
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Thomas A. Fanning |
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1,461,568 |
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1,415,361 |
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David J. Grain |
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20,793 |
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10,002 |
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Kimberly S. Greene |
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299,603 |
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299,603 |
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Veronica M. Hagen |
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37,138 |
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37,138 |
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Warren A. Hood, Jr. |
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47,524 |
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46,863 |
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Linda P. Hudson |
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2,696 |
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2,696 |
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Donald M. James |
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98,581 |
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98,581 |
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John D. Johns (5) |
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22,365 |
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21,915 |
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450 |
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Dale E. Klein |
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12,690 |
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12,690 |
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Stephen E. Kuczynski |
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629,919 |
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619,320 |
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William G. Smith, Jr. |
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64,331 |
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57,535 |
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862 |
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Steven R. Specker |
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11,937 |
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11,937 |
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Larry D. Thompson (6) |
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13,347 |
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1,120 |
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E. Jenner Wood III |
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24,204 |
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19,204 |
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Directors, Nominees, and Executive Officers as a
Group (25 people) (7) |
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6,513,643 |
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426,935 |
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5,774,784 |
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1,363 |
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(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. |
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:
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Title of Class |
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Name and Address |
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Shares Beneficially Owned (1) |
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Percentage of Class Owned (2) |
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Common Stock |
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Blackrock, Inc. 55 East
52nd Street New York, NY 10022 |
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52,684,667 |
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5.79 |
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Common Stock |
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State Street Corporation
One Lincoln Street Boston, MA 02111 |
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46,254,789 |
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5.08 |
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Common Stock |
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The Vanguard Group
100 Vanguard Blvd. Malvern, PA 19355 |
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51,373,414 |
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5.65 |
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(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. |
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
Companys 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 Companys executive compensation program based on the belief that executive compensation should:
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Be competitive with the Companys industry peers; |
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Motivate and reward achievement of the Companys goals; |
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Be aligned with the interests of the Companys stockholders and its subsidiaries customers; and |
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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 Companys financial success, business unit financial and operational success, and total shareholder return. The Companys financial and
operational achievement in 2014 resulted in performance-based awards that were aligned with performance.
All decisions concerning the compensation of the
Companys 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 Companys executive compensation program.
The affirmative vote of a
majority of the votes cast is required for approval of the following resolution:
RESOLVED, that the Companys stockholders approve, on an advisory
basis, the compensation of the Companys 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.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ITEM
NO. 4. |
INDEX TO EXECUTIVE
COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS (CD&A)
This section describes the compensation program for the Companys Chief Executive Officer and Chief Financial Officer in 2014, as well as the compensation program
for each of the Companys other three most highly compensated executive officers serving at the end of the year. Also described is the compensation of Alabama Powers 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.
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Thomas A.
Fanning |
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Chairman of the Board, President, and Chief Executive Officer |
Art P. Beattie |
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Executive Vice President and Chief Financial Officer |
W. Paul Bowers |
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Executive Vice President of the Company and Chairman, President, and Chief Executive Officer of Georgia Power |
Kimberly S. Greene (1) |
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Executive Vice President and Chief Operating Officer of the Company |
Stephen E. Kuczynski |
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President and Chief Executive Officer of Southern Nuclear Operating Company (Southern Nuclear) |
Charles D. McCrary |
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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). |
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.
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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:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
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.
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 Companys lower total shareholder return relative to the performance
share peer groups.
Compensation and Benefit Beliefs and Practices
The Companys 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 Companys executive compensation program should:
¡ |
Be competitive with the Companys industry peers; |
¡ |
Motivate and reward achievement of the Companys goals; |
¡ |
Be aligned with the interests of the Companys 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 Companys 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 Companys stockholders. Therefore, short-term performance pay is based on achievement of the Companys 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.
|
|
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 Companys 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 Companys Human Resources staff and, for individual executive officer performance, from the Companys 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 Companys 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 Companys executive compensation program is competitive, aligned with the Companys 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
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 Companys 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 Companys 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.
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 Companys 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 Companys 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
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
Companys 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 Companys 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
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 Committees 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 individuals 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 systems 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 Companys 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; |
¡ |
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 Companys 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).
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 Companys 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 Companys 2014 Proxy Statement, the Compensation Committee did not follow its usual practice, and the charges taken in 2013 related to
Mississippi Powers 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 Commissions 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 Powers 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 Powers 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 Companys financial ability to fund the Common Stock dividend. The 2014 Kemper IGCC Charges and Adjustments described above did not have that effect.
Goal Details and 2014 Performance Results
|
|
|
|
|
Financial Performance
Goals |
|
Description |
|
Why It Is Important |
EPS |
|
The Companys 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 Companys 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 Companys 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 Powers 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. |
|
|
|
|
|
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 Powers 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 Companys Chief Executive Officer or the Companys 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 Companys Target Zero program is focused on continuous improvement in having a safe work environment. The performance is measured by the applicable
companys 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 Companys 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. |
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 |
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 officers 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. McCrarys payout is prorated based on the amount of time he was employed at Alabama Power during 2014. Mr. Kuczynskis 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. |
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 |
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 systems 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 Companys 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
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 Companys total shareholder return relative to that of its peers in a custom peer group. While in previous years the Companys 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 Companys 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.
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 Companys 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. |
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 recipients interests with those of the Companys 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. Kuczynskis 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. McCrarys 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 Companys 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
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 Companys 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 Companys 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 Companys 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 Companys
long-term performance-based
compensation program to further align the Companys 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 Companys 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 Companys 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.
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 Companys 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 Companys 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 Companys policy is that employees and outside Directors
will not trade Company options on the options market and will not engage in short sales.
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 Companys 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 Companys 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 Companys performance share peer group.
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 Companys 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
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.
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Name and Principal
Position
(a)
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Year
(b)
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|
Salary
($)
(c)
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|
Bonus
($)
(d)
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Stock
Awards
($)
(e)
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Option
Awards
($)
(f)
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Non-Equity
Incentive
Plan
Compensation
($)
(g)
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|
Change
in Pension Value and Nonqualified
Deferred
Compensation
Earnings
($)
(h)
|
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All Other
Compensation
($)
(i)
|
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|
Total
($)
(j)
|
|
Thomas A. Fanning
Chairman, President,
and Chief Executive
Officer |
|
|
2014 |
|
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1,192,067 |
|
|
|
|
|
|
|
3,383,968 |
|
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|
2,255,999 |
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1,713,600 |
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2,899,537 |
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70,822 |
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11,515,993 |
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2013 |
|
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1,152,389 |
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|
|
|
|
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3,128,625 |
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2,085,747 |
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1,199,307 |
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805,738 |
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66,485 |
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8,438,291 |
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2012 |
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1,114,846 |
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|
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|
3,037,473 |
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|
2,025,000 |
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2,078,158 |
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4,712,413 |
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67,458 |
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13,035,348 |
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Art P. Beattie
Executive Vice
President and Chief
Financial Officer |
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2014 |
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668,516 |
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929,415 |
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619,617 |
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772,839 |
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1,396,842 |
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37,293 |
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4,424,522 |
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2013 |
|
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|
644,039 |
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|
|
|
|
|
|
796,514 |
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|
|
531,025 |
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437,126 |
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|
402,101 |
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|
122,037 |
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2,932,842 |
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2012 |
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615,378 |
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773,330 |
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515,558 |
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737,382 |
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2,747,374 |
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34,352 |
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5,423,374 |
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W. Paul Bowers
Chairman, President,
and Chief Executive
Officer, Georgia Power |
|
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2014 |
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782,928 |
|
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45 |
|
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|
1,086,520 |
|
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|
724,350 |
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|
892,841 |
|
|
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1,504,316 |
|
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|
46,986 |
|
|
|
5,037,986 |
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2013 |
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|
760,482 |
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|
|
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|
|
|
1,031,940 |
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|
687,964 |
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498,775 |
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44,375 |
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3,023,536 |
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2012 |
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739,587 |
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42 |
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1,003,813 |
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669,227 |
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1,013,366 |
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2,024,578 |
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50,830 |
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5,501,443 |
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Kimberly S. Greene Executive Vice President
and Chief Operating Officer |
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2014 |
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650,000 |
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701,998 |
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467,999 |
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580,125 |
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326,334 |
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605,315 |
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3,331,771 |
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2013 |
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475,000 |
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2,000,005 |
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1,039,997 |
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310,811 |
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212,666 |
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656,035 |
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4,694,514 |
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Stephen E. Kuczynski
President and Chief
Executive Officer,
Southern Nuclear |
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2014 |
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667,120 |
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1,681,742 |
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454,507 |
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734,564 |
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217,633 |
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39,117 |
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3,794,683 |
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2013 |
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658,378 |
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635,283 |
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423,534 |
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426,183 |
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126,714 |
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42,692 |
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2,312,784 |
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2012 |
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640,289 |
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617,967 |
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411,997 |
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619,288 |
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77,727 |
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101,886 |
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2,469,154 |
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Charles D. McCrary
Former Chairman,
President, and
Chief Executive Officer,
Alabama Power |
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2014 |
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389,266 |
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2,896,902 |
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722,920 |
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333,990 |
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923,064 |
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96,937 |
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5,363,079 |
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2013 |
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|
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799,124 |
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|
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|
1,084,347 |
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|
|
722,922 |
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|
650,630 |
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414,103 |
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45,396 |
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3,716,522 |
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2012 |
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|
|
777,167 |
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3,054,840 |
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703,232 |
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1,028,204 |
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2,437,448 |
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44,722 |
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8,045,613 |
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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
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 officers 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 officers 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 officers 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.
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.
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|
Perquisites
($)
|
|
|
Tax
Reimbursements
($)
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|
ESP
($)
|
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|
SBP
($)
|
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|
Total
($)
|
|
T. A. Fanning |
|
|
10,023 |
|
|
|
|
|
|
|
13,260 |
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|
47,539 |
|
|
|
70,822 |
|
A. P. Beattie |
|
|
5,022 |
|
|
|
|
|
|
|
11,437 |
|
|
|
20,834 |
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|
|
37,293 |
|
W. P. Bowers |
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|
7,464 |
|
|
|
|
|
|
|
12,853 |
|
|
|
26,669 |
|
|
|
46,986 |
|
K. S. Greene |
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|
400,708 |
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|
|
171,457 |
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|
13,260 |
|
|
|
19,890 |
|
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|
605,315 |
|
S. E. Kuczynski |
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9,241 |
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9,113 |
|
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|
20,763 |
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|
39,117 |
|
C. D. McCrary |
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|
84,345 |
|
|
|
|
|
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|
11,199 |
|
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|
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 Companys 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. Greenes 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 $32,379 for this approved personal use of corporate aircraft.
Other Miscellaneous
Perquisites. The amount included reflects the full cost to the Company of providing the following items: personal use of Company-provided tickets for sporting and other entertainment events and gifts distributed to and activities provided
to attendees at Company-sponsored events.
GRANTS OF PLAN-BASED AWARDS IN 2014
This table provides information on stock option grants made and goals established for future payouts under the performance-based compensation programs during 2014 by
the Compensation Committee.
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Name (a)
|
|
Grant Date
(b) |
|
|
Estimated Future Payouts Under
Non- Equity Incentive Plan Awards |
|
|
Estimated Future Payouts Under Equity Incentive Plan Awards |
|
|
All Other Stock
Awards: Number of Shares of Stock or Units
(#) (i) |
|
|
All Other Option
Awards: Number of Securities
Underlying Options (#)
(j) |
|
|
Exercise or Base
Price of Option Awards
($/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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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
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.
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 |
|
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 ($49.11). The
ultimate number of shares earned, if any, will be based on the actual performance results at the end of each respective performance period. The ultimate number of shares earned by Mr. McCrary will be prorated based on the number of months he
was employed by Alabama Power during the performance periods. See further discussion of performance shares in the CD&A. See also Potential Payments upon Termination or Change-in-Control for more information about the treatment of performance
shares under different termination and change-in-control events.
OPTION EXERCISES AND STOCK VESTED IN 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Awards |
|
|
Stock Awards |
|
Name
(a) |
|
Number of
Shares
Acquired on
Exercise
(#)
(b)
|
|
|
Value Realized on
Exercise
($)
(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 ($45.83).
PENSION BENEFITS AT 2014 FISCAL YEAR-END
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name (a) |
|
Plan Name
(b)
|
|
Number of
Years Credited
Service
(#)
(c)
|
|
|
Present Value
of
Accumulated
Benefit
($)
(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 Companys 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 participants 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
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 Plans benefit formulas produce amounts payable monthly over a participants 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
retirees 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 survivors 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 survivors 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-Ps vesting and early retirement provisions mirror those of the Pension Plan. Its disability provisions mirror those of the Pension Plan but cease upon a participants 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 retirees single sum will be
credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a key man under Section 409A of the Code, the first
installment will be delayed for six months after the date of separation.
If a SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the
deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participants 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 SERPs early retirement, survivor benefit, disability, and form of payment provisions mirror the SBP-Ps 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.
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
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 |
|
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 Companys compensation and benefit program or the change-in-control severance program. All of the
named executive officers are participants in Southern Companys 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 Companys 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 Companys 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 Companys 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 Companys subsidiaries,
consummation of a merger with another entity and the Companys subsidiary is not the surviving company, or the sale of substantially all the assets of any of the Companys 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
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 committees 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. |
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 companys 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 companys 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 companys 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. |
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.
|
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|
|
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|
|
|
Retirement
($)
|
|
|
Resignation
or Involuntary
Termination
|
|
|
Death
(payments
to a spouse)
($)
|
|
T. A. Fanning |
|
Pension |
|
|
8,207 |
|
|
|
treated as retiring |
|
|
|
4,998 |
|
|
|
SBP-P |
|
|
1,239,797 |
|
|
|
treated as retiring |
|
|
|
1,239,797 |
|
|
|
SERP |
|
|
506,098 |
|
|
|
treated as retiring |
|
|
|
506,098 |
|
A. P. Beattie |
|
Pension |
|
|
10,689 |
|
|
|
treated as retiring |
|
|
|
5,740 |
|
|
|
SBP-P |
|
|
568,034 |
|
|
|
treated as retiring |
|
|
|
568,034 |
|
|
|
SERP |
|
|
219,450 |
|
|
|
treated as retiring |
|
|
|
219,450 |
|
W. P. Bowers |
|
Pension |
|
|
8,737 |
|
|
|
treated as retiring |
|
|
|
5,256 |
|
|
|
SBP-P |
|
|
640,352 |
|
|
|
treated as retiring |
|
|
|
640,352 |
|
|
|
SERP |
|
|
210,117 |
|
|
|
treated as retiring |
|
|
|
210,117 |
|
K. S. Greene |
|
Pension |
|
|
|
|
|
|
628 |
|
|
|
1,031 |
|
|
|
SBP-P |
|
|
|
|
|
|
192,311 |
|
|
|
22,072 |
|
|
|
SERP |
|
|
|
|
|
|
|
|
|
|
29,307 |
|
S. E. Kuczynski |
|
Pension |
|
|
|
|
|
|
|
|
|
|
406 |
|
|
|
SBP-P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SERP |
|
|
|
|
|
|
|
|
|
|
|
|
As described in the Change-in-Control chart, the only change in the form of payment, acceleration, or enhancement of the
pension benefits is that the single sum value of benefits earned up to the change-in-control date under the SBP-P and the SERP could be paid as a single payment rather than in 10 annual installments. Also, the SERP benefits vest for participants who
are not retirement-eligible upon a change in control. Estimates of the single
sum payment that would have been made to the named executive officers, assuming termination as of December 31, 2014 following a change-in-control-related event, other than a Company
Change-in-Control I (which does not impact how pension benefits are paid), are itemized below. These amounts would be paid instead of the benefits shown in the Traditional Termination Events chart above; they are not paid in addition to those
amounts.
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|
|
|
|
|
|
|
|
SBP-P
($)
|
|
|
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.
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 companys stock options. It also shows the number and value of performance shares and restricted stock units that would be paid.
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|
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|
|
|
|
|
|
|
|
|
|
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
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 Committees 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
Companys executive officers served on the Board of Directors of any entities whose executive officers serve on the Compensation Committee.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2014 concerning shares of Common Stock authorized for issuance under Southern Companys 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. |
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 Companys financial statements, including the compensation of such firm and the related audit fee negotiations.
Deloitte &
Touche has served as the Companys 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 & Touches lead engagement partner in connection with the mandatory rotation requirements of the SEC.
The Audit Committee has appointed Deloitte & Touche as the Companys 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 Companys 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.
|
|
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|
|
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ITEM
NO. 5. |
AUDIT COMMITTEE REPORT
The Audit Committee oversees the Companys 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 Companys consolidated financial statements. In fulfilling its oversight
responsibilities, the Audit Committee reviewed the audited consolidated financial statements of the Company and its subsidiaries and managements report on the Companys 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 Companys quarterly and annual reporting on Forms 10-Q and 10-K prior to filing with the SEC. The Audit Committees 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 Companys 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
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 firms provision of non-audit services to the Company is compatible with maintaining the firms independence.
The Audit Committee discussed the overall scope and plans with the Companys 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 Companys internal control over financial reporting, and the overall quality of the Companys financial reporting. The Audit Committee also meets privately with the Companys 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 Companys 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 Companys 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 Companys 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 & Touches 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 & Touches 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.
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 Companys 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 Companys 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 Nominators 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 Companys 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 Institutes 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. |
|
¡ |
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 Companys shares to require the Company
to undertake the effort and expense of including their Director nominees in the Companys proxy materials and thus trigger a proxy contest, is an untested governance feature for U.S. companies. The Board of Directors continually evaluates the
Companys governance profile and believes that proxy access should not be implemented in the absence of a compelling rationale. The proponents 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 Companys 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 Companys 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 systems 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). |
|
¡ |
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 Companys certificate of incorporation and By-Laws, so the Board of Directors cannot unilaterally take away any rights granted to stockholders in the Companys
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 Companys 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 Boards commitment to refreshment is reflected in its overall
average Board tenure, which is less than six years.
Implementing proxy access could negatively affect the Companys 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 Companys proxy statement, bypassing the Companys 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
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 managements and the Boards attention, and potentially discourage highly-qualified Directors from serving.
Providing proxy access for a group of stockholders owning just 3% of the Companys 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 proponents resolution is the
affirmative vote of a majority of the votes cast.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE AGAINST ITEM NO. 6. |
ITEM NO. 7 GREENHOUSE GAS
EMISSIONS REDUCTION GOALS 2015
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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 countrys 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
percent by 2025. The EPAs 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.
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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 systems operations. Independently establishing these types of goals would not add value to the Companys already robust
research, development, and deployment efforts relating to new technology to reduce GHG emissions, would be premature given the Environmental Protection Agencys (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 systems 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 systems GHG emissions in 2014 were almost 20% lower than 2005 levels.
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 systems 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 DOEs 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 (TRIGTM) designed to produce less carbon dioxide emissions than the current fleet of existing coal plants. The
Companys subsidiary, Mississippi Power, is constructing the Kemper IGCC using TRIGTM 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 nations 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 Companys 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 Companys 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 systems operations due to (1) the Southern Company systems already robust research, development, and deployment efforts relating to new
technology to reduce GHG emissions, (2) the EPAs pending regulations governing GHG emissions from new and existing sources, which are not yet finalized, and (3) the Companys 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
Companys current efforts in this area.
The vote needed to pass the proponents resolution is the affirmative vote of a majority of the votes cast.
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THE BOARD OF DIRECTORS RECOMMENDS A VOTE AGAINST
ITEM NO. 7. |
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. |
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 Companys 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.
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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. |
Q: |
Can the Proxy Statement be accessed from the internet? |
A: |
Yes. You can access the Companys 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 drivers 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 Boards 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 Companys proxy materials for the 2016
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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 years meeting will confer discretionary authority to vote on any stockholder proposal presented at that meeting that is not included in the
Companys 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 Companys 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 Companys common stock. |
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING
COMPLIANCE
Based on the Companys review of Forms 3, 4, and 5 and amendments thereto in the Companys 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
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.
APPENDIX A
OUTSIDE DIRECTORS STOCK PLAN
OUTSIDE
DIRECTORS STOCK PLAN FOR
THE SOUTHERN COMPANY AND ITS SUBSIDIARIES
Outside Directors Stock Plan for The Southern Company and its Subsidiaries
Article IPurpose 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 IIDefinitions
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 Companys 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.
Article IIIEligibility
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 IVForm 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 Participants death.
Article VAdministration 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.
Article VIMiscellaneous
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 9th day of February, 2015, to be effective as provided herein.
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THE SOUTHERN COMPANY: |
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By: |
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Its: |
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Secretary |
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Attest: |
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By: |
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Its: |
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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 Participants Retainer Fee required to be distributed in Stock shall be determined in accordance with the following schedule:
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Company |
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Dollar Amount of Required Stock
Distribution |
Southern Company |
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$105,000 |
Alabama Power Company |
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$30,000 |
Georgia Power Company |
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$30,000 |
Gulf Power Company |
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$19,500 |
Mississippi Power Company |
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$19,500 |
APPENDIX B
PROPOSED AMENDMENT TO SECTION 46 OF THE
COMPANYS BY-LAWS
The text of the proposed amendment to
Section 46 of the Companys 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.
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. |
|
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 Committees approval of the independent auditors 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
APPENDIX D
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 Companys common stock with the Standard & Poors Electric Utility
Index and the Standard & Poors 500 index for the past five years. The graph assumes that $100 was invested on December 31, 2009 in the Companys 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.
TWENTY-YEAR CUMULATIVE PERFORMANCE GRAPH
This performance graph compares the cumulative total shareholder return on the Companys common stock with the Standard & Poors Electric Utility
Index and the Standard & Poors 500 index for the past 20 years. The graph assumes that $100 was invested on December 31, 1994 in the Companys common stock and each of the above indices and that all dividends were
reinvested. The distribution of shares of Mirant Corporation stock to the Companys stockholders in 2001 is treated as a special dividend for purposes of calculating the Companys shareholder return. The stockholder return shown below for
the twenty-year historical period may not be indicative of future performance.
MANAGEMENTS 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 managements supervision, an
evaluation of the design and effectiveness of Southern Companys internal control over financial reporting was conducted based on the framework in Internal ControlIntegrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Companys 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 Companys financial statements, has issued an attestation
report on the effectiveness of Southern Companys internal control over financial reporting as of December 31, 2014. Deloitte & Touche LLPs report on Southern Companys 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 |
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 Companys 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 Companys 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 Managements 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 Companys 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 companys internal control over financial reporting is a process
designed by, or under the supervision of, the companys principal executive and principal financial officers, or persons performing similar functions, and effected by the companys 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 companys 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 companys 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 |
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 PSCs 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 |
Moodys |
|
Moodys Investors Service, Inc. |
MPUS |
|
Mississippi Public Utilities Staff |
MW |
|
Megawatt |
NCCR |
|
Georgia Powers Nuclear Construction Cost Recovery |
NDR |
|
Alabama Powers 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 Powers Rate Certificated New Plant |
Rate CNP Environmental |
|
Alabama Powers Rate Certificated New Plant Environmental |
Rate CNP PPA |
|
Alabama Powers Rate Certificated New Plant Power Purchase Agreement |
Rate ECR |
|
Alabama Powers rate energy cost recovery |
Rate NDR |
|
Alabama Powers natural disaster reserve rate |
Rate RSE |
|
Alabama Powers rate stabilization and equalization plan |
ROE |
|
Return on equity |
S&P |
|
Standard and Poors 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 |
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 |
MANAGEMENTS 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 systems 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 Powers 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 Companys 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 Companys 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 systems 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 systems 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 Companys 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 Companys
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 Powers construction of the Kemper IGCC and the 2015 Mississippi Supreme Court decision, is calculated by excluding from EPS, as
MANAGEMENTS 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 Powers 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 PSCs 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 Companys 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 Companys 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 Companys financial performance.
Earnings
Southern
Companys 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 Powers
construction of the Kemper IGCC. These increases were partially offset by increases in non-fuel operations and maintenance expenses.
Southern Companys 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 Powers 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 Powers 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 systems 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Electricity Business
Southern
Companys 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.
MANAGEMENTS 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 systems generation, demand for energy within the Southern Company systems service territory, and the
availability of the Southern Company systems 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 systems 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 Powers 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 Powers 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.
MANAGEMENTS 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 Powers 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.
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Details of the Southern Company systems 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 Powers 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 systems service territory, the market prices of wholesale energy as compared to the cost of the Southern Company systems generation, and the availability of the Southern Company systems
generation.
MANAGEMENTS 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 Powers 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 Powers 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 Powers 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 Powers 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.
MANAGEMENTS 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 Powers 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 Powers Kemper IGCC and increased capital expenditures at Alabama Power, partially offset by the completion of Georgia Powers 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 SMEPAs 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 Powers Kemper IGCC, and an increase in capitalized interest associated with the construction of
Southern Powers Plants Campo Verde and Spectrum. These decreases were partially offset by a decrease in capitalized interest resulting from the completion of Southern Powers Plants Nacogdoches and Cleveland, a reduction in AFUDC debt due
to the completion of Georgia Powers 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 Powers 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 Companys 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.
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
A condensed statement of income for Southern Companys 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
Companys 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.
MANAGEMENTS 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 Companys 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 Companys future earnings
depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company systems 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
MANAGEMENTS 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 EPAs 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 systems 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
MANAGEMENTS 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 systems 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 systems 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 EPAs 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 EPAs 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
MANAGEMENTS 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 EPAs 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 systems 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 EPAs 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 Companys 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
MANAGEMENTS 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 EPAs proposed Clean Power Plan establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired
electric generating units. The EPAs 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 Companys 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 EPAs 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 EPAs 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 EPAs 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 EPAs greenhouse gas reporting rule requires annual reporting of CO2 equivalent emissions in metric tons for a companys operational control of facilities. Based on ownership or financial control of facilities, the Southern Company systems 2013
greenhouse gas emissions were approximately 102 million metric tons of CO2 equivalent. The preliminary estimate of the Southern Company systems 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 Powers 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 Powers rate mechanisms and accounting orders.
Rate RSE
Alabama Powers 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 Powers 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%.
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Rate CNP
Alabama Powers
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 industrys 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 EITFs 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 Powers 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 units 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 Powers 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 Companys 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
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Powers 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 Powers 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 PSCs 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:
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Traditional base tariffs by approximately $107 million to cover additional capacity costs; |
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ECCR tariff by approximately $23 million; |
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DSM tariffs by approximately $3 million; and |
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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 Powers 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 Powers earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on Georgia Powers 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 Powers 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 Georgias Multi-Pollutant Rule; and Georgia Powers 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 Powers latest triennial Integrated Resource Plan (2013 IRP) including
Georgia Powers 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.
MANAGEMENTS 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 Georgias 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 Powers 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 Powers 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 Companys financial statements; however, the ultimate
outcome depends on the Georgia PSCs 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 Companys 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 Powers 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 Powers 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 Companys statements of income and these changes
could be material.
MANAGEMENTS 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 Contractors 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 Powers 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 Contractors revised forecast, to include the estimated owners 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 Contractors 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 Companys 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 SMEPAs 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 Powers
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.
MANAGEMENTS 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 Companys 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 Companys 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 Companys 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 Companys Board of Directors.
Electric Utility Regulation
Southern Companys traditional operating companies, which comprised approximately 94% of Southern Companys 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 Companys 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 Companys 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 Companys 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 Companys financial position, results of operations, or
cash flows.
Pension and Other Postretirement Benefits
Southern
Companys 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,
MANAGEMENTS 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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
MANAGEMENTS 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 Powers 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 Companys 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 Companys 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 Companys cash requirements primarily consist of funding ongoing
operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company systems 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 systems cash needs. For the three-year period from 2015 through 2017, Southern Companys
projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Southern Company systems 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 Companys 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.
MANAGEMENTS 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 Companys 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 Companys 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 Companys investment opportunities and the Southern Company systems 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 Powers reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Powers 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 Powers 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.
MANAGEMENTS 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 Companys 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:
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Expires |
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Executable Term Loans |
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Due Within One Year |
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Company |
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2015 |
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2016 |
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2017 |
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2018 |
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Total |
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Unused |
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|
|
|
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.
MANAGEMENTS 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.
MANAGEMENTS 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 Companys Consolidated Financial Statements. This loan was repaid on September 29, 2014. |
In May 2014, Southern Companys $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 Companys outstanding short-term indebtedness and for other general corporate purposes.
Southern Companys 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 Powers 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.
MANAGEMENTS 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, Moodys 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 companys policies in areas such as counterparty exposure and risk
management practices. The Southern Company systems 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.
MANAGEMENTS 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 Powers 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
systems energy-related derivative contracts were designated as regulatory hedges and were related to the applicable companys 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.
MANAGEMENTS 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 Moodys 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 Companys 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 Companys 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 systems 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 SMEPAs 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 systems 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 EPAs 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 Powers 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,
MANAGEMENTS 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 SMEPAs 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.
|
MANAGEMENTS 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 Companys 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 Companys subsidiaries. |
Cautionary Statement Regarding Forward-Looking Statements
Southern Companys 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 Companys 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; |
|
|
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; |
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
|
|
investment performance of Southern Companys employee and retiree benefit plans and the Southern Company systems 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 systems 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 Companys 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 Companys 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 systems 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.
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.
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.
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.
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.
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.
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 |
|
|
|
|
|
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.
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.
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2014 Annual Report
Index to the Notes to Financial Statements
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 Companys investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company systems nuclear power plants.
The financial statements reflect Southern Companys 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.
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 Powers 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 |
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 companys 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 Companys 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.
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 systems 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 units operating cycle. The refueling cycles for Alabama Powers Plant Farley and Georgia Powers 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.
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 Powers portion of the purchase price. |
(d) |
Reflects 100% of the purchase price, including Turner Renewable Energy, LLCs 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 Powers 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 Powers 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 assets 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 assets 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 systems 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 systems 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
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 Powers and SEGCOs 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 Powers updated decommissioning study and Georgia Powers 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 Companys 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 NRCs 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.
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 NRCs 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 Powers Plant Farley and in 2012 for the Georgia Power plants, were
as follows for Alabama Powers Plant Farley and Georgia Powers 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES (continued)
For ratemaking purposes, Alabama Powers decommissioning costs are based on the site study, and Georgia
Powers 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
Powers 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 PSCs 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 Powers
NDR and Georgia Powers 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 Companys 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 |
|
|
|
|
|
|
|
|
|
|
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 systems 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 Companys 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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
trusts 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 trusts target asset allocation, an
anticipated inflation rate, and the projected impact of a periodic rebalancing of each trusts 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
Companys 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 |
) |
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 Companys 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 |
|
|
|
|
|
|
|
|
|
|
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 |
|
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 Companys 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 |
|
|
|
|
|
|
|
|
|
|
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 |
|
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 Companys 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 Companys 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 Companys 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 Companys 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. |
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
plans 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 policys 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.
|
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.
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.
|
NOTES (continued)
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 employees 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 Companys 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 Companys 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 Mirants 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
NOTES (continued)
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 Powers
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 partys failure to comply with the UAO.
In addition to the EPAs 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 Powers 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 Divisions 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 Powers regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern
Companys financial statements.
Gulf Powers 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 Powers 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
NOTES (continued)
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 systems 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 Companys 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 Companys 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 Powers 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 Powers 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 Powers 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 Powers 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%.
NOTES (continued)
Rate CNP
Alabama Powers
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 industrys 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 EITFs 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 Powers 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 Powers 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 Powers 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 Powers 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
NOTES (continued)
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 Powers 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 units 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 Powers 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 Companys 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 courts 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 DOEs 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
NOTES (continued)
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 Powers 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 PSCs 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:
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Traditional base tariffs by approximately $107 million to cover additional capacity costs; |
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ECCR tariff by approximately $23 million; |
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DSM tariffs by approximately $3 million; and |
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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 Powers 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-
NOTES (continued)
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 Powers earnings back to a 10.00%
retail ROE. The Georgia PSC would have 90 days to rule on Georgia Powers 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 Powers 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 Powers latest triennial Integrated Resource Plan (2013 IRP) including Georgia Powers 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
Georgias 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 Powers 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 Powers 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 Companys financial statements; however, the ultimate
outcome depends on the Georgia PSCs 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 Powers 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 Powers 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 Powers next fuel case filing until at least June 30, 2015.
Georgia Powers 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 Powers 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 Companys revenues or net income, but will affect cash flow.
NOTES (continued)
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 Companys 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 Contractors failure to fulfill the
schedule and performance guarantees. The Contractors 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 Powers 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 Powers
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&Is 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 Contractors 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
NOTES (continued)
additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Powers 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 Powers 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 Powers 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 Contractors 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
Contractors revised forecast reflects all efforts that may be possible to mitigate the Contractors delay.
In addition, Georgia Power believes that,
pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractors costs related to the Contractors 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 Contractors delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractors
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 Contractors 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 Contractors 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 Contractors proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to
the Contractors 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 Contractors revised forecast, to include the estimated owners 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.
NOTES (continued)
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 Powers 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
Powers 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 Powers 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 Powers actual retail ROE falls below the authorized ROE range.
Integrated Coal Gasification Combined Cycle
Kemper IGCC Overview
Construction of Mississippi Powers 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)
NOTES (continued)
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 Powers Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Courts (Court) decision), and actual costs incurred as of
December 31, 2014, as adjusted for the Courts 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 Powers 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 projects 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
NOTES (continued)
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 Companys 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
Companys results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Powers recovery of financing costs during the course of construction of the Kemper IGCC
and Mississippi Powers 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 Powers 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 Powers 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 Courts decision did not impact Mississippi Powers 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.
NOTES (continued)
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 Powers analysis requested, among other things, confirmation of Mississippi Powers 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 Powers August 18, 2014 filing with the Mississippi PSC requested confirmation of
Mississippi Powers 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 Powers 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 Courts 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 Courts 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 Courts 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 Courts decision and expects to file a motion for rehearing which would stay the Courts mandate until either the case is reheard
and decided or seven days after the Court issues its order denying Mississippi Powers 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 Powers 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 years 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.
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 PSCs 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 Courts 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 Powers 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.
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 SMEPAs 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 SMEPAs 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
SMEPAs 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 SMEPAs 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 SMEPAs 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
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 SMEPAs 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 Companys
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
Companys statement of income. In addition, and consistent with Mississippi Powers 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
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 Powers, Georgia Powers, and Southern Powers 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 subsidiarys 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.
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.
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 Companys 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 Companys 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.
NOTES (continued)
The IRS has finalized its audits of Southern Companys 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 Companys 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
Companys 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 trusts 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 Powers continuous construction program.
In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal
amount of $400 million.
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 Powers reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia
Powers 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 Powers rights and
obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Powers 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 DOEs 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 FFBs 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.
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 Powers rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to
acquire all or a portion of Georgia Powers 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 Powers 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 Powers 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.
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 Powers 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 Powers 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 Companys 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 Powers 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 Powers 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 Powers
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 subsidiarys 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 Companys 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.
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 systems 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.
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 Companys 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 |
NOTES (continued)
Southern Companys 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 Companys total shareholder return (TSR) over the three-year performance period which measures Southern Companys 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 Companys 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 Companys 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 Companys 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 |
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 members 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.
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 Companys 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 Companys 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.
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. |
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.
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 NRCs regulations. The foreign equity fund in Georgia Powers 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 funds 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
Powers 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 Powers 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 Powers nuclear
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 Companys 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 companys policies in areas such as counterparty exposure and risk management practices. Each companys 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.
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.
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.
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES (continued)
The Companys derivative contracts are not subject to master netting arrangements or similar agreements and are
reported gross on the Companys 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
Companys 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 Companys 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 systems 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 Companys statements of
income for the years ended December 31, 2014, 2013, and 2012. This third party hedging activity has been discontinued.
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 Companys 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 Moodys 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 Companys, the traditional operating companies, and Southern Powers 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
Companys 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 |
|
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 |
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 systems business is influenced by seasonal weather
conditions.
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.
|
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 |
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|
|
9.46 |
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Industrial |
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|
6.37 |
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|
|
6.08 |
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|
|
5.94 |
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|
6.37 |
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|
6.20 |
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Total retail |
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|
9.62 |
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|
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9.29 |
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|
|
9.09 |
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9.44 |
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|
|
9.01 |
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Wholesale |
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|
6.66 |
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|
|
6.88 |
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6.08 |
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6.28 |
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|
|
6.12 |
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Total sales |
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9.12 |
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|
8.94 |
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|
8.64 |
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8.93 |
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8.53 |
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Average Annual Kilowatt-Hour |
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Use Per Residential Customer |
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13,765 |
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13,144 |
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13,187 |
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13,997 |
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15,176 |
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Average Annual Revenue |
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Per Residential Customer |
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$ |
1,679 |
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$ |
1,562 |
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$ |
1,540 |
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$ |
1,645 |
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$ |
1,659 |
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Plant Nameplate Capacity |
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Ratings (year-end) (megawatts) |
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46,549 |
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45,502 |
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45,740 |
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43,555 |
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42,961 |
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Maximum Peak-Hour Demand (megawatts): |
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Winter |
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37,234 |
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27,555 |
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31,705 |
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34,617 |
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35,593 |
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Summer |
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35,396 |
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33,557 |
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35,479 |
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|
36,956 |
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36,321 |
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System Reserve Margin (at peak) (percent)* |
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|
19.8 |
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21.5 |
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|
20.8 |
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19.2 |
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23.3 |
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Annual Load Factor (percent) |
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|
59.6 |
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63.2 |
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59.5 |
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59.0 |
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62.2 |
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Plant Availability (percent)**: |
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|
|
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Fossil-steam |
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85.8 |
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87.7 |
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89.4 |
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88.1 |
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91.4 |
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Nuclear |
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91.5 |
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|
91.5 |
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94.2 |
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93.0 |
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92.1 |
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Source of Energy Supply (percent): |
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Coal |
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39.3 |
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36.9 |
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35.2 |
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48.7 |
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55.0 |
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Nuclear |
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14.8 |
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15.5 |
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16.2 |
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15.0 |
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14.1 |
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Hydro |
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|
2.5 |
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3.9 |
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1.7 |
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2.1 |
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2.5 |
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Oil and gas |
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37.4 |
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37.3 |
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|
|
38.3 |
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28.0 |
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|
23.7 |
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Purchased power |
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|
6.0 |
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6.4 |
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8.6 |
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6.2 |
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|
4.7 |
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Total |
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|
100.0 |
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|
100.0 |
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|
100.0 |
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|
100.0 |
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100.0 |
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* |
Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. |
** |
Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
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 Companys 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 Companys 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.
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 Nuclears Midwest operations, Senior Vice President of Operations Support, and Plant Manager and later Site Vice President for Exelons 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 Powers 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.
STOCKHOLDER INFORMATION
Transfer Agent
Computershare Inc. (Computershare) is Southern Companys 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 Computershares 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 Companys 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 Companys 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 Companys principal executive office is located at 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.
Recycled Paper Logo
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C/O PROXY SERVICES
P.O. BOX 9112 FARMINGDALE,
NY 11735 |
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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 |
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TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK
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M84919-P59459 |
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KEEP THIS PORTION FOR YOUR RECORDS |
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DETACH AND RETURN THIS PORTION ONLY |
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THIS PROXY CARD IS VALID ONLY WHEN SIGNED AND DATED.
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THE SOUTHERN COMPANY
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The Board of Directors recommends a vote FOR each nominee in Item 1.
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1. |
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ELECTION OF DIRECTORS: |
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For |
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Against |
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Abstain |
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1a. |
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J. P. Baranco |
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1b. |
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J. A. Boscia |
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1c. |
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H. A. Clark III |
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1m. |
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S. R. Specker |
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1d. |
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T. A. Fanning |
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1n. |
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L. D. Thompson |
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D. J. Grain |
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1o. |
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E. J. Wood III |
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The Board of Directors recommends a vote FOR Items 2, 3, 4, and
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1f. |
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V. M. Hagen |
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2. |
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APPROVAL OF THE OUTSIDE DIRECTORS STOCK PLAN |
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1g. |
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W. A. Hood, Jr. |
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APPROVAL OF AN AMENDMENT TO THE BY-LAWS RELATED TO THE ABILITY OF STOCKHOLDERS TO ACT BY WRITTEN CONSENT TO AMEND THE BY-LAWS |
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1h. |
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L. P. Hudson |
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4. |
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ADVISORY VOTE TO APPROVE NAMED EXECUTIVE OFFICERS
COMPENSATION |
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1i. |
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D. M. James |
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RATIFICATION OF THE APPOINTMENT OF DELOITTE & TOUCHE LLP AS THE
COMPANYS INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2015 |
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1j. |
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J. D. Johns |
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The Board of Directors recommends a vote AGAINST Items 6 and
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1k. |
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D. E. Klein |
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6. |
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STOCKHOLDER PROPOSAL ON PROXY ACCESS |
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1l. |
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W. G. Smith, Jr. |
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7. |
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STOCKHOLDER PROPOSAL ON GREENHOUSE GAS EMISSIONS REDUCTION GOALS |
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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. |
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Signature [PLEASE SIGN WITHIN BOX] |
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Date
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Signature (Joint Owners) |
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Date
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ADMISSION TICKET
(Not Transferable)
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2015 Annual Meeting of Stockholders |
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10 a.m. ET, May 27, 2015 |
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The Lodge Conference Center at Callaway Gardens Highway 18
Pine Mountain, GA 31822 |
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Please present this Admission Ticket in order to gain admittance to the meeting.
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Ticket admits only the stockholder(s) listed on reverse side and is not transferable. |
Directions to Meeting Site: |
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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
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FORM OF PROXY AND
TRUSTEE VOTING INSTRUCTION FORM |
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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 Companys 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.