def14a
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 S
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Filed
by a Party other than the Registrant £
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Check the
appropriate box:
£ Preliminary
Proxy Statement
£ Confidential,
for Use of the Commission Only (as permitted by Rule 14a-6(e) (2))
S Definitive
Proxy Statement
£ Definitive
Additional Materials
£ Soliciting
Materials Pursuant to Rule 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 the
Registrant)
Payment
of Filing Fee (Check the appropriate box):
S No
fee required.
£ Fee
computed on table below per Exchange Act Rules 14a-6(i) (1) and
0-11.
(1) Title
of each class of securities to which transaction applies:
_______________________________________________________________________________
(2) Aggregate
number of securities to which transaction applies:
_______________________________________________________________________________
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(3)
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Per
unit price or other underlying value of transaction computed pursuant to
Exchange Act Rule 0-11 (set forth the amount on which the filing fee is
calculated and state how it was
determined):
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_______________________________________________________________________________
(4) Proposed
maximum aggregate value of transaction:
_______________________________________________________________________________
(5) Total
fee paid:
_______________________________________________________________________________
£ Fee
paid previously with preliminary materials.
£
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Check
box if any part of the fee is offset as provided by Exchange Act Rule
0-11(a)(2) and identify the filing for which the offsetting fee was paid
previously. Identify the previous filing by registration statement number,
or the Form or Schedule and the date of its
filing.
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(1) Amount Previously Paid:
_______________________________________________________________________________
(2) Form,
Schedule or Registration Statement No.:
_______________________________________________________________________________
(3) Filing
Party:
_______________________________________________________________________________
(4) Date
Filed:
_______________________________________________________________________________
Notice of
Annual
Meeting
2010
&
Proxy Statement
PROXY STATEMENT
Contents
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David M. Ratcliffe
Chairman, President and
Chief Executive Officer
Dear Fellow Stockholder:
You are invited to attend the 2010 Annual Meeting of
Stockholders at 10:00 a.m., ET, on Wednesday, May 26,
2010 at The Lodge Conference Center at Callaway Gardens, Pine
Mountain, Georgia.
At the meeting, I will report on our business and our plans for
the future. Also, we will elect our Board of Directors and vote
on the other matters set forth in the accompanying Notice.
Your vote is important. Please review the proxy material and
vote by internet, phone, or mail as soon as possible.
We look forward to seeing you on May
26th.
David M. Ratcliffe
TIME AND DATE
10:00 a.m., ET, on Wednesday, May 26, 2010
PLACE
The Lodge Conference Center at Callaway Gardens
Highway 18
Pine Mountain, Georgia 31822
DIRECTIONS
From Atlanta, Georgia take I-85 south to I-185 (Exit
21). From I-185 south, take Exit 34, Georgia Highway 18. Take
Georgia Highway 18 east to Callaway.
From Birmingham, Alabama take U.S. Highway 280
east to Opelika. Take I-85 north to Georgia Highway 18 (Exit 2).
Take Georgia Highway 18 east to Callaway.
ITEMS OF
BUSINESS
(1) Elect 11 members of the Board of Directors;
(2) Ratify appointment of independent registered public
accounting firm;
(3) Consider and vote on an amendment to the By-Laws of the
Company to adopt a majority vote standard;
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(4)
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Consider and vote on an amendment to the Companys
Certificate of Incorporation to eliminate cumulative voting in
election of directors;
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(5)
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Consider and vote on an amendment to the Companys
Certificate of Incorporation to increase the number of
authorized shares of common stock;
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(6)
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and (7) Consider and vote on the stockholder proposals, if
presented at the meeting, as described in Item Nos. 6 and 7
of the Proxy Statement; and
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(8)
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Transact other business properly coming before the meeting or
any adjournments thereof.
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RECORD DATE
Stockholders of record at the close of business on
March 30, 2010 are entitled to attend and vote at the
meeting.
ANNUAL REPORT TO
STOCKHOLDERS
Appendix C to this Proxy Statement is Southern
Companys 2009 Annual Report.
By Order of the Board of Directors, G. Edison
Holland, Jr., Corporate Secretary, April 13, 2010
Even if you plan to attend the meeting in person, please provide
your voting instructions in one of the following ways as soon as
possible by either the Internet, the Phone using the toll-free
number, or the 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!
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VOTE BY INTERNET
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VOTE BY PHONE
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www.proxyvote.com
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1-800-690-6903
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24 hours a day/7 days a week
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Toll-free 24 hours a day/7 days a week
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Instructions:
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Instructions:
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n Read this Proxy
Statement
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n Read this Proxy
Statement
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n Go to the following
website:
www.proxyvote.com
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Have your proxy form or voting instruction
form in hand and follow the instructions.
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Have your proxy form or voting instruction
form in hand and follow the instructions.
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Voting
early will ensure the presence of a quorum at the meeting and
will save the
Company the expense and extra work of additional
solicitation.
Please do not return the enclosed paper ballot if you are voting
over the Internet or by Phone.
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Q: |
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When will the Proxy Statement be mailed? |
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The Proxy Statement will be mailed on or about April 13,
2010. |
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How do I give voting instructions? |
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You may attend the meeting and give instructions in person or,
as mentioned previously, give instructions by the Internet, by
telephone, or by mail. Information for giving instructions is on
the proxy form. The Proxies, named on the enclosed proxy form,
will vote all properly executed proxies that are delivered
pursuant to this solicitation and not subsequently revoked in
accordance with the instructions given by you. |
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Why is my vote important? |
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It is the right of every investor to vote on certain important
matters that affect the Company. Further, for those investors
whose shares are held by a broker, in 2009, the New York Stock
Exchange and the Securities and Exchange Commission (SEC) each
adopted rule changes. As a result of these rule changes, you
must complete and return a voting instruction form to instruct
the broker on how to vote in the election of Directors. Brokers
can no longer vote uninstructed shares of their account holders
in the election of Directors. |
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Can I change my vote? |
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Yes, you may revoke your proxy by submitting a subsequent proxy
or by written request received by the Companys corporate
secretary before the meeting. |
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Who can vote? |
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All stockholders of record on the record date of March 30,
2010 may vote. On that date, there were
825,020,642 shares of Southern Company common stock (Common
Stock) outstanding and entitled to vote. |
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How much does each share count? |
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Each share counts as one vote, except votes for Directors may be
cumulative. Abstentions that are marked on the proxy form are
included for the purpose of determining a quorum, but shares
that a broker fails to vote are not counted toward a quorum.
Neither is counted for or against the matters being considered;
however, abstentions and broker non-votes have the effect of a
vote against Item Nos. 4 and 5. |
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What does it mean if I get more than one proxy form? |
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You will receive a proxy form for each account that you have.
Please vote proxies for all accounts to ensure that all your
shares are voted. If you wish to consolidate multiple registered
accounts, please contact Stockholder Services at
(800) 554-7626. |
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Can the Companys Proxy Statement be accessed from the
Internet? |
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Yes. You can access the Companys website at
www.southerncompany.com to view the 2010 Proxy Statement. |
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Does the Company offer electronic delivery of proxy
materials? |
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Yes. Most stockholders can elect to receive an
e-mail that
will provide an electronic link to the Proxy Statement, which
includes the 2009 Annual Report as an appendix. Opting to
receive your proxy materials on-line will save us the cost of
producing and mailing documents and also will give you an
electronic link to the proxy voting site. |
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You may sign up for electronic delivery when you vote your proxy
via the Internet or: |
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n Go
to our investor website at
http://investor.southerncompany.com/;
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n Click
on the words Electronic Delivery of Proxy Materials;
and
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n Follow
the directions provided to complete your enrollment.
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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 |
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the Proxy Statement, which includes the 2009 Annual Report as an
appendix. The Company will continue to distribute printed
materials to stockholders who do not consent to access these
materials electronically. |
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What is householding? |
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Certain beneficial owners of the Common Stock sharing a single
address may receive only one copy of the Proxy Statement, which
includes the 2009 Annual Report as an appendix, unless the
broker, bank, or nominee has received contrary instructions from
any beneficial owner at that address. This practice
known as householding is designed to reduce printing
and mailing costs. If a beneficial owner would like to either
participate or cancel participation in householding, he or she
may contact Stockholder Services at
(800) 554-7626
or at 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308 and
ask to receive a Proxy Statement, which will be delivered
promptly. As noted earlier, beneficial owners may view the Proxy
Statement on the Internet. |
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When are stockholder proposals due for the 2011 Annual
Meeting of Stockholders? |
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The deadline for the receipt of stockholder proposals to be
considered for inclusion in the Companys proxy materials
for the 2011 Annual Meeting of Stockholders is December 13,
2010. Proposals must be submitted in writing to Melissa K. Caen,
Assistant Corporate Secretary, Southern Company, 30 Ivan Allen
Jr. Boulevard NW, Atlanta, Georgia 30308. Additionally, the
proxy solicited by the Board of Directors for next 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 26, 2011. |
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Who pays the expense of soliciting proxies? |
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These proxies are being solicited on behalf of the
Companys Board of Directors. The Company pays the cost of
soliciting proxies. The officers or other employees of the
Company or its subsidiaries may solicit proxies to have a larger
representation at the meeting. The Company has retained Laurel
Hill Advisory Group to assist with the solicitation of proxies
for a fee not to exceed $10,000, plus reimbursement of
out-of-pocket
expenses. |
The
Companys 2009 Annual Report to the SEC on
Form 10-K
will be provided without charge upon written request to Melissa
K. Caen, Assistant Corporate Secretary, Southern Company, 30
Ivan Allen Jr. Boulevard NW, Atlanta,
Georgia 30308.
Important notice regarding the availability of proxy
materials for the Annual Meeting of Stockholders to be held on
May 26, 2010:
This Proxy Statement, which includes the 2009 Annual Report as
an appendix, is also available at
http://investor.southerncompany.com/proxy.cfm.
2
Corporate Governance
COMPANY
ORGANIZATION
Southern Company is a holding company managed by a core group of
officers and governed by a Board of Directors that is currently
comprised of 12 members.
At the 2010 Annual Meeting, stockholders will elect
11 Directors. The nominees for election as Directors
consist of 10 non-employees and one executive officer of the
Company.
The Board of Directors has adopted and operates under a set of
Corporate Governance Guidelines which are available on the
Companys website at www.southerncompany.com under
Investors/Corporate Governance.
CORPORATE
GOVERNANCE WEBSITE
In addition to the Corporate Governance Guidelines (which
include Board independence criteria), other information relating
to corporate governance of the Company is available on the
Companys Corporate Governance webpage at
www.southerncompany.com under Investors/Corporate Governance or
directly at
http://investor.southerncompany.com/governance.cfm,
including:
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Code of Ethics |
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Political Contributions Policy and Report |
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By-Laws of the Company |
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Executive Stock Ownership Guidelines |
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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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SEC filings |
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Composition of Board Committees |
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Link for online communication with Board of Directors |
The Corporate Governance documents also may be obtained by
requesting a copy from Melissa K. Caen, Assistant Corporate
Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW,
Atlanta, Georgia 30308.
DIRECTOR
INDEPENDENCE
No Director will be deemed to be independent unless the Board of
Directors affirmatively determines that the Director has no
material relationship with the Company, directly, or as an
officer, stockholder, or partner of an organization that has a
relationship with the Company. The Board of Directors has
adopted categorical guidelines which provide that a Director
will not be deemed to be independent if within the preceding
three years:
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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 received, or the Directors immediate family
member received, during any
12-month
period, direct compensation from the Company of more than
$120,000, other than director and committee fees. (Compensation
received by an immediate family member for services as a
non-executive employee of the Company need not be considered.) |
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The Director was affiliated with or employed by, or the
Directors immediate family member was affiliated or
employed in a professional capacity by, a present or former
external auditor of the Company. |
3
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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 executives serves
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
of the last three fiscal years, exceeds the greater of
$1,000,000 or two percent of that companys consolidated
gross revenues. |
Additionally, a Director will be deemed not to be independent if
the Director or the Directors spouse serves as an
executive officer of a charitable organization to which the
Company made discretionary contributions exceeding the greater
of $1,000,000 or two percent of the organizations total
annual charitable receipts.
In determining independence, the Board reviews and considers all
commercial, consulting, legal, accounting, charitable, or other
business relationships that a Director or the Directors
immediate family members have with the Company. This review
specifically included all ordinary course transactions with
entities with which the Directors are associated. In particular,
the Board reviewed transactions between subsidiaries of the
Company and The Home Depot, Inc. and Vulcan Materials Company as
described under Certain Relationships and Related Transactions
on page 64 of this Proxy Statement. Messrs. Francis S.
Blake, a former Director, and Donald M. James are the Chief
Executive Officers of The Home Depot, Inc. and Vulcan Materials
Company, respectively. The Board determined that its
subsidiaries followed the Company procurement policies and
procedures, that the amounts were well under the thresholds
contained in the Director independence requirements, and that
neither Mr. Blake nor Mr. James had a direct or
indirect material interest in the transactions.
Ms. Elizabeth Blake, the wife of Mr. Francis S. Blake,
a former Director of the Company, is a Senior Vice President of
Government Relations and Advocacy, and General Counsel for
Habitat for Humanity International. In 2009, the Company,
primarily through its foundation and the foundations of its
subsidiaries, supported Habitat for Humanity International
through charitable contributions of approximately $80,000. No
other Director or immediate family member serves in an executive
capacity for a charitable organization. The Board reviewed all
contributions made by the Company and its subsidiaries to
charitable organizations with which the Directors are
associated. The Board determined that the contributions were
consistent with similar contributions and none were approved
outside the Companys normal procedures.
As a result of its annual review of Director independence, the
Board affirmatively determined that none of the following
persons who are currently serving as Directors or are nominees
for election as Directors has a material relationship with the
Company and, as a result, such persons are determined to be
independent: Juanita Powell Baranco, Jon A. Boscia, Thomas F.
Chapman, Henry A. Clark III, H. William Habermeyer, Jr.,
Veronica M. Hagen, Warren A. Hood, Jr., Donald M. James, J.
Neal Purcell, William G. Smith, Jr., Gerald J. St. Pé,
and Larry D. Thompson. Also, Francis S. Blake, who served as a
Director during 2009 until his resignation date of
October 7, 2009, was determined not to have a material
relationship with the Company and to be independent. David M.
Ratcliffe, a current Director, is Chairman of the Board,
President, and Chief Executive Officer of the Company and is not
independent.
COMMUNICATING
WITH THE BOARD
Communications may be sent to the Companys Board or to
specified Directors, including the Presiding Director, by
regular mail or electronic mail. Regular mail should be sent to
the attention of Melissa K. Caen, Assistant Corporate Secretary,
Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta,
Georgia 30308. The electronic mail address is
CORPGOV@southerncompany.com. The electronic mail address also
can be accessed from the Corporate Governance webpage located
under Investors on the Southern Company website at
www.southerncompany.com, under the link entitled
Governance Inquiries. With the exception of
commercial solicitations, all stockholder communications
directed to the Board or to specified Directors will be relayed
to them.
4
DIRECTOR
COMPENSATION
Only non-employee Directors are compensated for Board service.
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Annual retainers: |
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$85,000 cash retainer |
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$12,500 if serving as a chair of a committee of the Board |
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$12,500 if serving as the Presiding Director of the Board |
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Annual equity grant: |
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$90,000 in deferred Common Stock units until Board membership
ends |
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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. |
DIRECTOR
DEFERRED COMPENSATION PLAN
The $90,000 equity grant is required to be deferred in shares of
Common Stock under the Deferred Compensation Plan for Directors
of The Southern Company (Director Deferred Compensation Plan)
and invested in Common Stock units which earn dividends as if
invested in Common Stock. Earnings are reinvested in additional
stock units. Upon leaving the Board, distributions are made in
Common Stock.
In addition, Directors may elect to defer up to 100% of their
remaining compensation in the Director Deferred Compensation
Plan until membership on the Board ends. Such deferred
compensation may be invested as follows, at the 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 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 Common
Stock. Directors have voting rights in the shares held in the
trust attributable to these units.
5
DIRECTOR COMPENSATION TABLE
The following table reports all compensation to the
Companys non-employee Directors during 2009, including
amounts deferred in the Director Deferred Compensation Plan.
Non-employee Directors do not receive Option Awards or
Non-Equity Incentive Plan Compensation, and there is no pension
plan for non-employee Directors.
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Change in
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Pension Value
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Fees
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and
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Earned
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Non-Equity
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Nonqualified
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or Paid
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Stock
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Option
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Incentive Plan
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Deferred
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All Other
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in Cash
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Awards
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Awards
|
|
|
Compensation
|
|
|
Compensation
|
|
|
Compensation
|
|
|
|
|
Name
|
|
($)(1)
|
|
|
($)(2)
|
|
|
($)
|
|
|
($)
|
|
|
Earnings ($)
|
|
|
($)(3)
|
|
|
Total ($)
|
|
|
|
|
Juanita Powell Baranco
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,693
|
|
|
|
189,193
|
|
|
Francis S. Blake(4)
|
|
|
70,834
|
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
145,834
|
|
|
Jon A. Boscia
|
|
|
85,000
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000
|
|
|
Thomas F. Chapman
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187,500
|
|
|
Henry A. Clark III(5)
|
|
|
21,250
|
|
|
|
22,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,750
|
|
|
H. William Habermeyer, Jr.
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187,500
|
|
|
Veronica M. Hagen
|
|
|
99,584
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189,584
|
|
|
Warren A. Hood, Jr.
|
|
|
85,000
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000
|
|
|
Donald M. James
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187,500
|
|
|
J. Neal Purcell
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187,500
|
|
|
William G. Smith, Jr.
|
|
|
97,500
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
835
|
|
|
|
188,335
|
|
|
Gerald J. St. Pé
|
|
|
85,000
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000
|
|
|
|
|
|
(1) |
|
Includes amounts voluntarily deferred in the Director Deferred
Compensation Plan. |
(2) |
|
Represents deferred Common Stock units. |
(3) |
|
Consists of tax
gross-ups
for taxes associated with spousal air travel. |
(4) |
|
Mr. Blake resigned as a Director of the Company on
October 7, 2009. |
(5) |
|
Mr. Clark became a Director of the Company on
October 19, 2009. |
DIRECTOR
STOCK OWNERSHIP GUIDELINES
Under the 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 four times the annual Director retainer fee.
BOARD
LEADERSHIP STRUCTURE
The Board believes that the combined role of Chief Executive
Officer and Chairman is most suitable for the Company because
Mr. Ratcliffe is the Director most familiar with the
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 the discussion and execution of strategy. Independent
Directors and management have different perspectives and roles
in strategy development. The Chief Executive Officer brings
company-specific experience and expertise, while the
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.
6
The Board believes the combined role of Chief Executive Officer
and Chairman, together with an independent Presiding Director
having the duties described below, is in the best interest of
stockholders because it provides the appropriate balance between
independent oversight of management and the development of
strategy.
PRESIDING
DIRECTOR
Mr. Chapman served as the Presiding Director from
January 1, 2008 until December 31, 2009.
Mr. James was appointed to serve as the Presiding Director
effective January 1, 2010 until December 31, 2011. The
Presiding Director is selected bi-annually by and from the
independent Directors. Non-management Directors meet, without
management, at least quarterly, and at other times as deemed
appropriate by the Presiding Director or two or more other
independent Directors. As the Presiding Director, Mr. James
is responsible for chairing executive sessions and acting as the
principal liaison between the Chairman and the non-management
Directors. However, each Director is afforded direct and
complete access to the Chairman at any time as such Director
deems necessary or appropriate. The Presiding Director meets
regularly with the Chairman and also serves as the contact
Director for stockholders. The Presiding Director will also be
involved in communicating any sensitive issues to the Directors.
The Presiding Director also chairs Board meetings in the absence
of the Chairman.
MEETINGS
OF NON-MANAGEMENT DIRECTORS
Non-management Directors meet in executive session with no
member of management present on each regularly-scheduled Board
meeting date. The Presiding Director chairs each of these
executive sessions.
COMMITTEES
OF THE BOARD
Charters for each of the five standing committees can be found
at the Companys website
www.southerncompany.com under Investors/Corporate Governance.
|
|
|
|
|
Audit Committee: |
|
n
|
|
Members are Mr. Smith (Chair), Mr. Boscia (1),
and Mr. Hood |
|
n
|
|
Met 10 times in 2009 |
|
n
|
|
Oversees the Companys financial reporting, audit
processes, internal controls, and legal, regulatory, and ethical
compliance; appoints the Companys independent registered
public accounting firm, approves its services and fees, and
establishes and reviews the scope and timing of its audits;
reviews and discusses the Companys financial statements
with management and the independent registered public accounting
firm, including critical accounting policies and practices,
material alternative financial treatments within generally
accepted accounting principles, proposed adjustments, control
recommendations, significant management judgments and accounting
estimates, new accounting policies, changes in accounting
principles, any disagreements with management, and other
material written communications between the internal auditors
and/or the
independent registered public accounting firm and management;
and recommends the filing of the Companys annual financial
statements with the SEC. |
The Board has determined that the members of the Audit Committee
are independent as defined by the New York Stock Exchange
corporate governance rules within its listing standards and
rules of the SEC promulgated pursuant to the Sarbanes-Oxley Act
of 2002. The Board has determined that Mr. Smith qualifies
as an audit committee financial expert as defined by
the SEC.
(1) Mr. Blake resigned from the Board effective
October 7, 2009 and Mr. Boscia was appointed a member
of the Audit Committee effective October 19, 2009.
7
|
|
|
|
|
Compensation and Management Succession Committee
(Compensation Committee): |
|
n
|
|
Members are Mr. Purcell (Chair), Mr. Clark (1),
Mr. Habermeyer, and Mr. James |
|
n
|
|
Met eight times in 2009 |
|
n
|
|
Evaluates performance of executive officers and establishes
their compensation, administers executive compensation plans,
and reviews management succession plans. Annually reviews a
tally sheet of all components of the executive officers
compensation and takes actions required of it under the Pension
Plan for employees of the Company. |
The Board has determined that each member of the Compensation
Committee is independent.
(1) Mr. Boscia served as a member of the Compensation
Committee until October 19, 2009 and Mr. Clark was
appointed a member of the Compensation Committee effective
October 19, 2009.
During 2009, 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.
|
|
|
Receiving meeting materials several days in advance of meetings.
|
|
|
Having regular executive sessions of Compensation Committee
members only.
|
|
|
Having direct access to outside compensation consultants.
|
|
|
Conducting a performance/payout analysis versus peer companies
for the performance-based compensation program to provide a
check on the Companys goal-setting process.
|
|
|
Reviewing a compensation risk assessment process developed by
its outside compensation consultant.
|
|
|
|
|
|
Role of Executive Officers |
The Chief Executive Officer, with input from the 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 proposals.
|
|
|
|
|
Role of Compensation Consultant |
In 2009, the Compensation Committee directly retained Towers
Perrin as its outside compensation consultant. The Compensation
Committee informed Towers Perrin in writing that the
Compensation Committee expected Towers Perrin to provide an
independent assessment of the current executive compensation
program and any management-recommended changes to that program
and to work with the Companys management to ensure that
the executive compensation program is designed and administered
consistent with the Compensation Committees requirements.
The Compensation Committee also expected Towers Perrin to
recommend changes based on executive compensation and related
corporate governance trends.
During 2009, Towers Perrin assisted the Compensation Committee
with comprehensive market data and its implications for pay at
the Company and various other governance, design, and compliance
matters.
The Company engages human resources consulting firms, including
Towers Perrin, for various services including compensation and
benefits market studies, health and retirement actuarial
services, and health and wellness consulting. The services
provided by Towers Perrin in 2009 and the fees paid for those
services are listed below.
|
|
|
|
|
Engagement by the Compensation Committee (executive
compensation consulting)
|
|
$
|
582,876
|
|
Health and Welfare Plan Projects
|
|
$
|
560,959
|
|
Development of communications for compensation program
changes
|
|
$
|
118,544
|
|
8
The Compensation Committee does not believe that its
consultants independence was affected by the additional
services provided by the firm. However, beginning in 2010, all
such services must be approved in advance by the Chair of the
Compensation Committee, as provided in the Compensation
Committees Charter as amended effective February 15,
2010.
|
|
|
|
|
Compensation Committee Interlocks and Insider
Participation |
None of the persons who served as members of the Compensation
Committee during 2009 was an officer or employee of the Company
during 2009, or at any time in the past, nor had reportable
transactions with the Company.
|
|
|
|
|
Finance Committee: |
|
n
|
|
Members are Mr. Clark (Chair) (1), Mr. James
(2), and Mr. Purcell |
|
n
|
|
Met seven times in 2009 |
|
n
|
|
Reviews the Companys financial matters, recommends actions
such as dividend philosophy to the Board, and approves certain
capital expenditures. |
The Board has determined that each member of the Finance
Committee is independent.
(1) Mr. Clark was appointed a member of the Finance
Committee on October 19, 2009 and Chair of the Finance
Committee effective January 1, 2010. Mr. Boscia served
as a member of the Finance Committee until October 19, 2009.
(2) Mr. James, previously the Chair of the Finance
Committee, was appointed Presiding Director effective
January 1, 2010.
|
|
|
|
|
Governance Committee: |
|
n
|
|
Members are Ms. Baranco (Chair), Mr. Chapman,
Ms. Hagen (1), and Mr. St. Pé |
|
n
|
|
Met seven times in 2009 |
|
n
|
|
Oversees the composition of the Board and its committees,
determines non-management Directors compensation,
maintains the Companys Corporate Governance Guidelines,
and coordinates the performance evaluations of the Board and its
committees. |
The Board has determined that each member of the Governance
Committee is independent.
(1) Ms. Hagen was appointed a member of the Governance
Committee effective February 16, 2009.
|
|
|
|
|
Nominees for Election to the Board |
The Governance Committee, comprised entirely of independent
Directors, is responsible for identifying, evaluating, and
recommending nominees for election to the Board. The Governance
Committee solicits recommendations for candidates for
consideration from its current Directors and is authorized to
engage third-party advisers to assist in the identification and
evaluation of candidates for consideration. Any stockholder may
make recommendations to the Governance Committee by sending a
written statement setting forth the candidates
qualifications, relevant biographical information, and signed
consent to serve. These materials should be submitted in writing
to the Companys Assistant Corporate Secretary and received
by that office by December 13, 2010 for consideration by
the Governance Committee as a nominee for election at the Annual
Meeting of Stockholders to be held in 2011. Any stockholder
recommendation is reviewed in the same manner as candidates
identified by the Governance Committee or recommended to the
Governance Committee.
While the 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 would consider aspects
of diversity, such as diversity of age, race, gender, education,
industry, and public and private service in the selection of
candidates to serve on the Board. The Governance Committee only
considers candidates with the highest degree of integrity and
ethical standards. The Governance Committee evaluates a
candidates independence from management, ability to
provide sound and informed judgment, history of achievement
reflecting superior standards, willingness to commit sufficient
time, financial literacy, and number of other board memberships.
The Board as a whole should also have collective
9
knowledge and experience in accounting, finance, leadership,
business operations, risk management, corporate governance, and
the Companys industry. During 2009, the Governance
Committee engaged the services of a third-party search firm to
aid in identifying prospective candidates and evaluating their
qualifications. The Governance Committee recommends candidates
to the Board for consideration as nominees. Final selection of
the nominees is within the sole discretion of the Board.
Mr. Henry A. Clark III was recommended by the
Governance Committee for election to the Board and was elected
as a Director effective October 19, 2009. Mr. Clark
was identified jointly by management and the members of the
Governance Committee.
Mr. Larry D. Thompson was recommended by the Governance
Committee for nomination for election to the Board and was
selected as a nominee for election as a Director.
Mr. Thompson was identified jointly by the members of the
Governance Committee and the third-party search firm referenced
above.
|
|
|
|
|
Nuclear/Operations Committee: |
|
n
|
|
Members are Mr. Habermeyer (Chair),
Ms. Baranco, Ms. Hagen (1), and Mr. St. Pé |
|
n
|
|
Met five times in 2009 |
|
n
|
|
Oversees significant information, activities, and events
relative to significant operations of the Company including
nuclear and other generation facilities, transmission and
distribution, fuel, and information technology initiatives. |
(1) Ms. Hagen was appointed to the Nuclear/Operations
Committee effective February 16, 2009.
BOARD
RISK OVERSIGHT
The Board and its committees have both general and specific risk
oversight responsibilities. The Board has broad responsibility
to provide oversight of significant risks to the Company
primarily through direct engagement with Company management and
through delegation of ongoing risk oversight responsibilities to
the committees. The charters of the committees as approved by
the Board designate the areas of risk for which each committee
is responsible for providing ongoing oversight. Each committee
provides oversight of the significant risks as described in its
charter. The committees report to the Board on their oversight
activities and elevate review of risk issues to the Board as
appropriate. For each committee, the Chief Executive Officer of
the Company has designated a member of management as the primary
responsible officer for providing information and updates
related to the significant risks. These officers ensure that all
significant risks identified on the 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 also is
responsible for reviewing the adequacy of the risk oversight
process and for reviewing documentation demonstrating that
appropriate risk management and oversight are occurring. In
order to fulfill this duty, a report is made to the Audit
Committee at least annually. This report documents which
significant risk reviews have occurred and the committee(s)
reviewing such risks. In addition, an overview is provided at
least annually of the risk assessment and profile process
conducted by Company management. Annually, the Board and the
Audit Committee review the Companys risk profile to ensure
that oversight of each risk is properly designated to an
appropriate committee or the full Board. The Audit Committee
receives regular updates from Internal Auditing, as needed, and
quarterly updates as part of the disclosure controls process.
DIRECTOR
ATTENDANCE
The Board met seven times in 2009. The average attendance for
Directors at all Board and committee meetings was
95 percent. No nominee attended less than 75 percent
of applicable meetings.
Directors are expected to attend the Annual Meeting of
Stockholders. With the exception of Mr. Francis S. Blake, a
former Director, all the members of the Board of Directors
serving on May 27, 2009, the date of the 2009 Annual
Meeting of Stockholders, attended the meeting.
10
STOCK
OWNERSHIP OF DIRECTORS, NOMINEES, AND EXECUTIVE
OFFICERS
The following table shows the number of shares of Common Stock
owned by Directors, nominees, and executive officers as of
December 31, 2009. The shares owned by all Directors,
nominees, and executive officers as a group constitute less than
one percent of the total number of shares of the class
outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Beneficially Owned Include:
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
Individuals
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
Have Rights to
|
|
|
|
|
|
|
Beneficially
|
|
|
Deferred Stock
|
|
|
Acquire within
|
|
|
Shares Held by
|
|
Directors, Nominees, and Executive Officers
|
|
Owned(1)
|
|
|
Units(2)
|
|
|
60 days(3)
|
|
|
Family Members(4)
|
|
|
|
Juanita Powell Baranco
|
|
|
22,494
|
|
|
|
21,970
|
|
|
|
|
|
|
|
|
|
|
Jon A. Boscia
|
|
|
9,736
|
|
|
|
5,736
|
|
|
|
|
|
|
|
|
|
|
W. Paul Bowers
|
|
|
357,192
|
|
|
|
|
|
|
|
346,482
|
|
|
|
|
|
|
Thomas F. Chapman
|
|
|
41,958
|
|
|
|
41,958
|
|
|
|
|
|
|
|
|
|
|
Henry A. Clark III(5)
|
|
|
722
|
|
|
|
722
|
|
|
|
|
|
|
|
|
|
|
Thomas A. Fanning
|
|
|
434,751
|
|
|
|
|
|
|
|
427,157
|
|
|
|
|
|
|
Michael D. Garrett
|
|
|
423,193
|
|
|
|
|
|
|
|
421,059
|
|
|
|
|
|
|
H. William Habermeyer, Jr.
|
|
|
7,383
|
|
|
|
7,383
|
|
|
|
|
|
|
|
|
|
|
Veronica M. Hagen
|
|
|
6,185
|
|
|
|
6,185
|
|
|
|
|
|
|
|
|
|
|
Warren A. Hood, Jr.
|
|
|
15,271
|
|
|
|
14,748
|
|
|
|
|
|
|
|
|
|
|
Donald M. James
|
|
|
57,101
|
|
|
|
55,101
|
|
|
|
|
|
|
|
|
|
|
Charles D. McCrary
|
|
|
511,472
|
|
|
|
|
|
|
|
505,903
|
|
|
|
|
|
|
J. Neal Purcell
|
|
|
46,488
|
|
|
|
36,264
|
|
|
|
|
|
|
|
224
|
|
|
David M. Ratcliffe
|
|
|
2,873,398
|
|
|
|
|
|
|
|
2,854,768
|
|
|
|
|
|
|
William G. Smith, Jr.
|
|
|
25,625
|
|
|
|
21,594
|
|
|
|
|
|
|
|
|
|
|
Gerald J. St. Pé
|
|
|
108,506
|
|
|
|
54,041
|
|
|
|
|
|
|
|
9,342
|
|
|
Larry D. Thompson(6)
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
Directors, Nominees, and Executive Officers as a Group
(23 people)
|
|
|
6,278,843
|
|
|
|
265,702
|
|
|
|
5,849,568
|
|
|
|
9,566
|
|
|
|
|
(1) |
Beneficial ownership means the sole or shared power
to vote, or to direct the voting of, a security, or investment
power with respect to a security, or any combination thereof.
|
|
|
|
(2) |
|
Indicates the number of Deferred Stock Units held under the
Director Deferred Compensation Plan. |
|
(3) |
|
Indicates shares of Common Stock that certain executive officers
have the right to acquire within 60 days. Shares indicated
are included in the Shares Beneficially Owned column. |
|
(4) |
|
Each Director disclaims any interest in shares held by family
members. Shares indicated are included in the Shares
Beneficially Owned column. |
|
(5) |
|
Mr. Clark was elected as a Director of the Company on
October 19, 2009. |
|
(6) |
|
Mr. Thompson is a nominee for Director. |
11
STOCK
OWNERSHIP OF CERTAIN OTHER BENEFICIAL OWNERS
According to Schedule 13G filed with the SEC on
December 31, 2009, the following reported beneficial
ownership of more than 5% of the outstanding shares of Common
Stock as of December 31, 2009:
|
|
|
|
|
|
|
|
|
Name and Address
|
|
Shares Beneficially
Owned
|
|
Percentage of Class
Owned
|
|
Blackrock, Inc.
40 East
52nd
Street
New York, NY 10022
|
|
|
41,952,022
|
|
|
|
5.24
|
%
|
Blackrock, Inc. held all of these shares as a parent holding
company, or control person in accordance with
Rule 13(d)-1(b)(1)(ii)(G),
and had sole investment power over all of these shares and no
voting power over any of these shares and disclaimed beneficial
ownership of the shares. This information is based solely on the
Schedule 13G filed by Blackrock, Inc.
12
ITEM NO. 1
ELECTION OF DIRECTORS
Nominees
for Election as Directors
The Proxies named on the proxy form will vote, unless otherwise
instructed, each properly executed proxy form for the election
of the following nominees as Directors. If any named nominee
becomes unavailable for election, the Board may substitute
another nominee. In that event, the proxy would be voted for the
substitute nominee unless instructed otherwise on the proxy
form. Each nominee, if elected, will serve until the 2011 Annual
Meeting of Stockholders.
The Board of Directors, acting upon the recommendation of the
Governance Committee, nominates the following individuals for
election to the Southern Company Board of Directors. Each
nominee holds or has held senior executive positions, maintains
the highest degree of integrity and ethical standards, and
complements the needs of the Company. Through their positions,
responsibilities, skills, and perspectives, which span various
industries and organizations, these nominees represent a Board
that is diverse and possessing the collective knowledge and
experience in accounting, finance, leadership, business
operations, risk management, and corporate governance as
detailed below. The Governance Committee evaluated each
nominees independence from management, ability to provide
sound and informed judgment, history of achievement reflecting
superior standards, willingness to commit sufficient time,
financial literacy, community involvement, and the number of
other board memberships.
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Juanita Powell Baranco
Age:
Director since:
Board committees:
Principal occupation:
Director qualifications:
Other directorships:
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61
2006
Governance (Chair), Nuclear/Operations
Executive Vice President and Chief Operating Officer of Baranco
Automotive Group, automobile sales
Ms. Baranco had a successful law career, which included serving
as Assistant Attorney General for the State of Georgia, before
she and her husband founded the first Baranco dealership in
Atlanta in 1978. She served as a member of the board at Georgia
Power, the largest subsidiary of the Company, from 1997-2006.
During her tenure on the Georgia Power Board, she was a member
of the Controls and Compliance, Diversity, Executive, and
Nuclear Operations Overview Committees. She served on the
Federal Reserve Bank of Atlanta board for a number of years and
also on the John H. Harland Company Board of Directors. An
active leader in the Atlanta community, Ms. Baranco has served
as a Director of Cox Radio, Inc. She serves as Chair of the
Board of Trustees for Clark Atlanta University and Board Chair
for the Sickle Cell Foundation of Georgia. She is also past
Chair of the Board of Regents for the University System of
Georgia. The Board has benefitted from Ms. Barancos
particular expertise in business operations and her civic
involvement.
None (formerly a Director of Georgia Power and Cox Radio, Inc.)
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13
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Jon A. Boscia
Age:
Director since:
Board committee:
Principal occupation:
Director qualifications:
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57
2007
Audit
President of Sun Life Financial Inc., financial services
In September 2008, Mr. Boscia assumed the role of President of
Sun Life Financial Inc. In this capacity, Mr. Boscia manages a
portfolio of the companys operations, including the Sun
Life Financial U.S. business group, the investments function,
worldwide marketing and communications, the Bermuda operation
which markets products internationally, and other strategic
international initiatives. Previously, Mr. Boscia served as
Chairman of the Board and Chief Executive Officer of Lincoln
Financial Group, a diversified financial services organization,
until his retirement in 2007. Mr. Boscia became the Chief
Executive Officer of Lincoln Financial Group in 1998. During
his time at Lincoln Financial Group, the company earned a
reputation for its stellar performance in making major
acquisitions. Mr. Boscia is a past member of the board of The
Hershey Company where he chaired the Corporate Governance
Committee and served on the Executive Committee. In addition,
Mr. Boscia has served in leadership positions on other public
company boards as well as not-for-profit and industry boards.
His extensive background in finance, investment management, and
information technology are valuable to the Board.
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Other directorships:
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Armstrong World Industries (formerly a Director of Lincoln
Financial Group and The Hershey Company)
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14
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Henry A. Hal Clark III
Age:
Director since:
Board committees:
Principal occupation:
Director qualifications:
Other directorships:
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60
2009
Finance (Chair), Compensation and Management
Succession
Senior Advisor of Lexicon Partners, LLC, corporate finance
advisory firm, since July 2009
As a Senior Advisor with Lexicon Partners, LLC, Mr. Clark is
primarily focused on expanding advisory activities in North
America with a particular focus on the power and utilities
sectors. With more than 30 years of experience in the
global financial and the utility industries, Mr. Clark brings a
wealth of experience in finance and risk management to his role
as a Director. Prior to joining Lexicon Partners, Mr. Clark was
Group Chairman of Global Power and Utilities at Citigroup from
2001-2009. His work experience includes numerous capital
markets transactions of debt, equity, bank loans, convertibles,
and securitization, as well as advice in connection with mergers
and acquisitions. He also has served as policy advisor to
numerous clients on capital structure, cost of capital, dividend
strategies, and various financing strategies. He has served as
Chair of the Wall Street Advisory Group of the Edison Electric
Institute.
None
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15
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H. William Habermeyer, Jr.
Age:
Director since:
Board committees:
Director qualifications:
Other directorships:
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67
2007
Nuclear/Operations (Chair), Compensation and Management
Succession
Mr. Habermeyer retired in 2006 from his position as President
and Chief Executive Officer of Progress Energy Florida, Inc., a
subsidiary of Progress Energy Inc., a diversified energy
company. Mr. Habermeyer has a wealth of experience in utility
business operations, with a focus on nuclear matters. He joined
Progress Energys predecessor Carolina Power & Light
in 1993 and served in various leadership roles including Vice
President of Nuclear Services and Environmental Support, Vice
President of Nuclear Engineering, and Vice President of Progress
Energys Western Region. While overseeing the Western
Region operations, Mr. Habermeyer was responsible for regional
distribution management, customer support, and community
relations. He currently serves on the Compensation, and
Technology and Competition Committees of the board of USEC Inc.,
a global energy company, and the Audit Committee of Raymond
James Financial Inc. Mr. Habermeyer is a retired Rear Admiral
who served in the United States Navy for 28 years. His
military medals include seven awards of the Legions of Merit,
two Navy Commendation Medals, and service and campaign
awards.
Raymond James Financial Inc., USEC Inc.
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16
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Veronica M. Ronee Hagen
Age:
Director since:
Board committees:
Principal occupation:
Director qualifications:
Other directorships:
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64
2008
Governance, Nuclear/Operations
Chief Executive Officer of Polymer Group, Inc., engineered materials, since April 2007
Ms. Hagens global operational management experience and commercial business leadership are valuable assets to Southern Companys Board. Polymer Group is a public company which is the leading producer and marketer of engineered materials. Prior to joining Polymer Group, Ms. Hagen was the President and Chief Executive Officer of Sappi Fine Paper, a division of Sappi Limited, the South African-based global leader in the pulp and paper industry, from November 2004 until her resignation in 2007. She also has served as Vice President and Chief Customer Officer at Alcoa and owned and operated Metal Sales Associates, a privately-held metal business. Ms. Hagen also serves on the Operations and Safety and Environmental and Social Responsibility Committees of the board of Newmont Mining Corporation.
Polymer Group, Inc., Newmont Mining
Corporation
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17
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Warren A. Hood, Jr.
Age:
Director since:
Board committee:
Principal occupation:
Director qualifications:
Other directorships:
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58
2007
Audit
Chairman of the Board and Chief Executive Officer of Hood Companies Incorporated, packaging and construction products
Mr. Hood is the Chief Executive Officer of Hood Companies Incorporated which includes four separate corporations with 60 manufacturing and distribution sites throughout the United States, Canada, and Mexico. Mr. Hood previously served on the board of the Companys subsidiary, Mississippi Power, where he was also a member of the Compensation Committee. Mr. Hood has long been recognized for his leadership role in the State of Mississippi. He serves on numerous corporate, community, and philanthropic boards, including BancorpSouth Bank, Boy Scouts of America, and The Governors Commission on Rebuilding, Recovery and Renewal, which was formed following Hurricane Katrina in 2005.
Mr. Hoods business operations, risk management, and financial experience and civic involvement are valuable to the Board.
Hood
Companies Incorporated, BancorpSouth Bank (formerly a Director of Mississippi Power)
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18
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Donald M. James
Age:
Director since:
Board committees:
Principal occupation:
Director qualifications:
Other directorships:
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61
1999, Presiding Director since January 1, 2010
Compensation and Management Succession, Finance
Chairman of the Board and Chief Executive Officer of
Vulcan Materials Company, construction materials
Mr. James joined Vulcan Materials in 1992 as Senior Vice President and General
Counsel and then became President of the Southern Division and then Senior Vice President of the Construction Materials Group and President
of the Southern Division. Prior to joining Vulcan Materials, Mr. James was a partner at the law firm of Bradley, Arant, Rose & White
for 10 years. Mr. James is also a Director of the UAB Health System, Boy Scouts of Central Alabama, and the Economic Development
Partnership of Alabama, Inc. In addition, he serves on the Finance and Human Resources Committees of Wells Fargo & Companys
Board of Directors. Mr. James leadership of a large, public company, his legal expertise, and his civic involvement are valuable assets
to the Board.
Vulcan Materials Company, Wells Fargo & Company (formerly a Director of Protective Life Corporation)
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19
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J. Neal Purcell
Age:
Director since:
Board committees:
Director qualifications:
Other directorships:
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68
2003
Compensation and Management Succession (Chair), Finance
Mr. Purcell is a retired Vice-Chairman of KPMG. From October 1998 until his retirement in 2002, Mr. Purcell was in charge of National Audit Practice Operations. Over the course of his career at KPMG, he was a member of its Board of Directors and its Management Committee. He performed numerous peer review audits and quality of audits reviews during his career. Mr. Purcell is currently a Director of Kaiser Permanente Health Care and Hospitals and Synovus Financial Corp. where he is serves as the Chair of each Audit Committee. He also serves on the Board of Trustees of Emory University where he is Chair of the Compensation Committee and on the Board of Directors of Emory Healthcare System. His financial and accounting expertise, his knowledge of the communities served by Southern Companys affiliates, and his personal involvement in those communities are valuable to the Board. During his
time on the Board, Mr. Purcell has also chaired the Audit Committee and served as the Companys first audit committee financial expert.
Kaiser Permanente Health Care and Hospitals, Synovus Financial Corp. (formerly a Director of Dollar General Corporation)
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David M. Ratcliffe
Age:
Director since:
Principal occupation:
Director qualifications:
Other directorships:
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61
2003
Chairman of the Board, President, and Chief Executive Officer of the Company
As Southern Companys Chairman of the Board, Chief Executive Officer, and President, Mr. Ratcliffe is uniquely qualified to serve on the Board. As an employee with more than 39 years of service, Mr. Ratcliffe understands the electric utility business, the regulatory structure, and other industry-specific matters that affect Southern Company. He is also a Director of CSX Corporation where he currently serves on the Executive, and Operations and Public Affairs Committees and as Chair of the Finance Committee.
CSX Corporation, Alabama Power, Georgia Power, and Southern Power
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20
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William G. Smith, Jr.
Age:
Director since:
Board committee:
Principal occupation:
Director qualifications:
Other directorships:
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56
2006
Audit (Chair)
Chairman of the Board, President, and Chief Executive Officer of Capital City Bank Group, Inc., banking
Mr. Smith began his career at Capital City Bank in 1978, where he worked in a number of capacities before being elected President and Chief Executive Officer of Capital City Bank Group in January 1989. He was then elected Chairman of the Board of the Capital City Bank Group Inc., a public company, in 2003. He has also served on the Board of Directors of the Federal Reserve Bank of Atlanta. Mr. Smith serves on the Board of Trustees for Darlington School in Rome, Georgia, and the Florida State University Foundation. He is the former Federal Advisory Council Representative for the Sixth District of the Federal Reserve System and past Chair of both Tallahassee Memorial HealthCare and the Tallahassee Area Chamber of Commerce. Mr. Smiths experience in finance, business operations, and risk management is valuable to the
Board. In addition, Mr. Smith qualifies as an audit committee financial expert.
Capital City Bank Group, Inc., Capital City Bank
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21
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Larry D. Thompson
Age:
Director since:
Board committee:
Principal occupation:
Director qualifications:
Other directorship:
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64
Nominee
Not applicable
Senior Vice President - Government Affairs, General Counsel, and Secretary of PepsiCo, Inc., food and beverage
PepsiCo ranks among the worlds largest convenient food and beverage companies. In his current role at PepsiCo, Mr. Thompson is responsible for PepsiCos worldwide legal function, as well as its government affairs organization and the companys charitable foundation. Prior to joining PepsiCo in 2004, Mr. Thompson served as a Senior Fellow with The Brookings Institution. His government career also includes serving in the United States Department of Justice and leading the National Security Coordination Council. In 2002, President George W. Bush named Mr. Thompson to head the Corporate Fraud Task Force. Mr. Thompson is a director or trustee of various investment companies in the Franklin Templeton group of mutual funds and has recently been elected to the board of Cbeyond, Inc. Mr. Thompson
s corporate governance and legal expertise will be valuable to the Board.
Cbeyond, Inc.
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Each nominee has served in his or her present position for at
least the past five years, unless otherwise noted.
The affirmative vote of a plurality of shares present and
entitled to vote is required for the election of Directors.
Stockholders are entitled to cumulative voting in the election
of Directors. See Item No. 3 below for a discussion of
cumulative voting.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE FOR THE NOMINEES
LISTED IN ITEM NO. 1.
ITEM NO. 2
RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Audit Committee of the Board of Directors has appointed
Deloitte & Touche LLP (Deloitte & Touche) as
the Companys independent registered public accounting firm
for 2010. This appointment is being submitted to
stockholders for ratification. Representatives of
Deloitte & Touche will be present at the Annual
Meeting to respond to appropriate questions from stockholders
and will have the opportunity to make a statement if they desire
to do so.
The affirmative vote of a majority of shares present and
entitled to vote is required for ratification of the appointment
of the independent registered public accounting firm.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE FOR
ITEM NO. 2.
22
ITEM NO. 3
TO AMEND THE COMPANYS BY-LAWS TO (1) IMPLEMENT A
MAJORITY VOTE STANDARD FOR THE ELECTION OF DIRECTORS IN
UNCONTESTED ELECTIONS, RETAINING A PLURALITY VOTE STANDARD IN
CONTESTED ELECTIONS, AND (2) ELIMINATE CUMULATIVE VOTING IN
UNCONTESTED ELECTIONS, EACH CONDITIONED ON THE ELIMINATION OF
CUMULATIVE VOTING IN THE CERTIFICATE OF INCORPORATION
The Companys Board of Directors determined that it would
be in the best interest of the Company and its stockholders to
allow for majority voting and to eliminate cumulative voting in
uncontested elections of Directors. The Board recommends that
the stockholders approve an amendment to the By-Laws to change
the standard for the election of Directors in uncontested
elections from a plurality voting standard to a majority voting
standard and also to eliminate cumulative voting in uncontested
elections, subject to the elimination of cumulative voting in
the Certificate of Incorporation, as described more fully in
Item No. 4 below.
Under the current plurality vote standard, a nominee for
Director in an election can be elected or re-elected with as
little as a single affirmative vote, even while a substantial
majority of the votes cast are withheld from that
nominee. The proposed majority vote standard would require that
a nominee for Director in an uncontested election receive a
for vote from a majority of the votes present and
voting at a stockholders meeting to be elected to the
Board. Additionally, the By-Laws currently provide that when
electing Directors, stockholders may exercise cumulative voting
rights. Under cumulative voting, in voting for Directors each
holder of Common Stock is entitled to cast a number of votes
equal to the number of votes he or she would be entitled to cast
with respect to his or her shares of Common Stock multiplied by
the number of Directors to be elected. A stockholder may give
one candidate all the votes such stockholder is entitled to cast
or may distribute such votes among as many candidates as such
stockholder chooses. The Board feels that cumulative voting and
a majority vote standard are incompatible, and is recommending
the elimination of cumulative voting in uncontested elections in
conjunction with the adoption of a majority vote standard.
The Board is seeking to eliminate cumulative voting and to
implement a majority vote standard in uncontested elections
because it believes that such changes are in the best interest
of stockholders at this time. The Board recommends retaining
cumulative voting in the By-Laws for any contested election of
Directors, to which a plurality standard would apply. Please see
Item No. 4 below for additional information regarding
the proposed elimination of cumulative voting as contained in
the Certificate of Incorporation.
The proposed majority vote standard would require that a nominee
for Director in an uncontested election receive a majority of
the votes cast at a stockholder meeting in order to be elected
to the Board. The Board believes that the proposed majority vote
standard for uncontested elections is a more equitable standard.
At present, a plurality vote standard guarantees the election of
a Director in an uncontested election; however, a majority vote
standard would mean that nominees in uncontested elections are
only elected if a majority of the votes cast are voted in their
favor. The Board believes that this majority vote standard in
uncontested Director elections will strengthen the Director
nomination process and enhance Director accountability.
Additionally, the Board will add appropriate provisions to its
Corporate Governance Guidelines to require any nominee for
election as a Director of the Company to submit an irrevocable
letter of resignation as a condition to being named as such
nominee, which would be tendered in the event that nominee fails
to receive the affirmative vote of a majority of the votes cast
in an uncontested election at a meeting of stockholders. Such
resignation would be considered by the Board, and the Board
would be required to either accept or reject such resignation
within 90 days from the certification of the election
results.
The By-Laws also currently provide for cumulative voting in the
election of Directors. The proposed amendment would eliminate
cumulative voting in uncontested elections of Directors, but
retain cumulative voting in contested elections of Directors.
The Board does not believe that it should amend the By-Laws to
establish a majority vote standard and to eliminate cumulative
voting while the Companys Certificate of Incorporation
still provides for cumulative voting. The elimination of
cumulative voting is desirable in connection with the adoption
of the majority vote standard with respect to uncontested
elections. Because both the Certificate of Incorporation and the
By-Laws currently provide for cumulative voting, the Board
23
recommends that the provisions in the Certificate of
Incorporation relating to cumulative voting be eliminated. The
Board believes that less confusion will result if both the
majority vote standard and cumulative voting provisions are
contained only in the By-Laws rather than in both the By-Laws
and the Certificate of Incorporation. This proposed amendment
does not provide any less protection to stockholders because
under the Companys By-Laws, stockholders are required to
ratify any amendment to the By-Laws, and any further change in
either the majority vote standard or cumulative voting would be
subject to the stockholder ratification requirement.
The proposed By-Law amendment would include the following:
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The By-Laws will be amended to remove provisions about
cumulative voting for Directors in uncontested elections and
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The plurality voting provisions in the By-Laws will be replaced
with provisions requiring that, in order to be elected in an
uncontested election, a nominee for Director must receive the
affirmative vote of a majority of the votes cast at a meeting of
stockholders; provided that, in contested elections, the
affirmative vote of a plurality of the votes cast will be
required to elect a Director.
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A complete text of the amendment is set forth in Appendix A.
The affirmative vote of a majority of shares present and
entitled to vote is required for amendment of the By-Laws as
presented in this Item No. 3.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE FOR
ITEM NO. 3.
ADOPTION OF THIS ITEM NO. 3 IS CONDITIONED ON THE
APPROVAL BY STOCKHOLDERS OF ITEM NO. 4 BELOW. NEITHER
ITEM NO. 3 NOR ITEM NO. 4 WILL BE
IMPLEMENTED UNLESS BOTH ITEMS ARE APPROVED.
ITEM NO. 4
TO AMEND THE CERTIFICATE OF INCORPORATION TO ELIMINATE
CUMULATIVE VOTING IN ELECTIONS OF DIRECTORS, CONDITIONED UPON
ADOPTION OF THE MAJORITY VOTE STANDARD AND THE ELIMINATION OF
CUMULATIVE VOTING IN UNCONTESTED ELECTIONS IN THE
BY-LAWS
The Board has determined that it would be in the best interest
of the Company and its stockholders to require that a nominee
for Director in an uncontested election receive a majority of
the votes cast at a stockholders meeting to be elected to
the Board (see Item No. 3 above). The Board is seeking
to eliminate cumulative voting in uncontested elections because
it believes that a change to a majority vote standard in
uncontested elections is in the best interest of stockholders at
this time, and it views cumulative voting as inconsistent with a
majority vote standard for the election of Directors.
The elimination of cumulative voting in uncontested elections
requires an amendment to the By-Laws as discussed in
Item No. 3 above and also requires an amendment to the
Certificate of Incorporation, which would remove subdivision
(2) of ARTICLE NINTH (the cumulative voting
provision). The Board feels it is appropriate to remove
cumulative voting entirely from the Certificate of Incorporation
and to amend the cumulative voting provisions discussed above in
the By-Laws so that all of the provisions pertaining to voting
in Director elections are contained in the By-Laws. As discussed
above, cumulative voting will be permitted in a contested
election, to which the plurality voting standard applies.
This amendment to the Certificate of Incorporation has been
approved and declared advisable by the Board but requires
adoption by the Companys stockholders. This elimination
would facilitate adoption of the majority vote standard for the
election of Directors in the manner described above in
Item No. 3.
This item would not change the present number of Directors, and
the Board would retain the authority to change that number and
to fill any vacancies or newly created directorships.
24
The Board is seeking to eliminate cumulative voting because it
believes that a change to a majority vote standard in
uncontested elections would be in the best interest of
stockholders at this time and it views cumulative voting as
incompatible with a majority vote standard for election.
The proposed amendment would eliminate subdivision (2) of
ARTICLE NINTH of the Certificate of Incorporation in its
entirety.
Approval of this Item requires the affirmative vote of at
least two-thirds of the outstanding shares of the Companys
Common Stock.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE FOR
ITEM NO. 4.
ADOPTION OF THIS ITEM NO. 4 IS CONDITIONED ON THE APPROVAL
BY STOCKHOLDERS OF ITEM NO. 3 ABOVE. NEITHER
ITEM NO. 3 NOR ITEM NO. 4 WILL BE
IMPLEMENTED UNLESS BOTH ITEMS ARE APPROVED.
ITEM NO. 5
TO AMEND THE COMPANYS CERTIFICATE OF INCORPORATION TO
INCREASE THE NUMBER OF AUTHORIZED SHARES OF COMMON
STOCK
The Board has proposed and declared advisable, and is
recommending to the stockholders, approval of an amendment to
the Certificate of Incorporation of the Company to increase the
total number of shares of Common Stock, par value $5 per share,
that the Company has authority to issue, from 1,000,000,000 to
1,500,000,000.
Of the 1,000,000,000 shares that the Company presently is
authorized to issue, there were 825,020,642 shares
outstanding as of March 30, 2010. In addition, on
March 30, 2010, approximately 84,661,139 shares were
reserved for issuance under the Southern Investment Plan (a
dividend reinvestment and direct purchase plan) and the
Companys employee and director stock plans. The proposed
increase in the amount of authorized but unissued Common Stock
is considered necessary to provide the Company with the
flexibility in the future to issue shares of Common Stock for
future financing transactions, acquisitions, stock dividends or
distributions, stock splits, issuances under the Southern
Investment Plan and employee and director stock plans, and other
general corporate purposes. The additional shares of Common
Stock that will be available for issuance will be identical in
terms to the shares of Common Stock currently authorized under
the Certificate of Incorporation of the Company.
If the proposed amendment is adopted, the Company would be
permitted to issue the authorized shares without further
stockholder approval, except to the extent otherwise required by
law, by a securities exchange on which the Common Stock is
listed at the time, or by the Certificate of Incorporation. The
New York Stock Exchange, on which the Common Stock is now
listed, currently requires stockholder approval as a
prerequisite to listing shares in certain instances, including
acquisition transactions where the issuance could increase the
number of outstanding shares by 20% or more.
The additional shares of Common Stock that will be available for
issuance will be identical in terms to the shares of Common
Stock currently authorized under the Certificate of
Incorporation of the Company. Stockholders do not have
preemptive rights to subscribe for or purchase additional shares
of the Common Stock.
The Company has no current plans, agreements, or arrangements
for the issuance of additional Common Stock other than pursuant
to the Southern Investment Plan, the Companys employee and
director stock plans, and the Companys continuous equity
offering program. However, the additional authorized shares
would be available for issuance (subject to further stockholder
approval only as noted above) at such times and for such other
corporate purposes as the Board may approve, including possible
future financing transactions, acquisitions, stock dividends or
distributions, and stock splits and other general corporate
purposes.
Depending upon the nature and terms thereof, additional
issuances of the Common Stock could enable the Board to render
more difficult or discourage an attempt to obtain control of the
Company. For example, the issuance of shares of Common Stock in
a public or private sale, merger, or similar transaction would
increase the number of the Companys outstanding shares,
thereby diluting the interest of a party seeking to take over
the Company. If Item No. 5 is adopted, more Common
25
Stock of the Company would be available for such purposes than
is currently available. The proposed increase in the number of
authorized shares of Common Stock is not in response to any
effort by any person or group to obtain control of the Company.
Issuances of additional shares of Common Stock, depending upon
their timing and circumstances, also may dilute earnings per
share and decrease the book value per share of shares already
outstanding.
The vote needed to pass this proposed amendment of the
Certificate of Incorporation is a majority of the shares of the
Companys stock outstanding and entitled to vote. If
approved by stockholders, ARTICLE FOURTH of the Certificate
of Incorporation will be amended to read as follows:
The total number of shares of stock which the corporation
shall have authority to issue is 1,500,000,000 shares, all
of which are to be shares of common stock with a par value of
five dollars ($5) each.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE FOR
ITEM NO. 5.
ITEM NO. 6
STOCKHOLDER PROPOSAL ON CLIMATE CHANGE ENVIRONMENTAL
REPORT
The Company has been advised that The Sisters of Charity of
Saint Elizabeth, P. O. Box 476, Convent Station, New Jersey
07961-0476,
holder of 100 shares of Common Stock; American Baptist Home
Mission Societies, P. O. Box 851, Valley Forge,
Pennsylvania
19482-0851,
holder of 1,742 shares of Common Stock; Benedictine Sisters
Charitable Trust, 285 Oblate Drive, San Antonio, Texas
78216, holder of 100 shares of Common Stock; Benedictine
Sisters of Virginia, Saint Benedict Monastery, 9535 Linton Hall
Road, Bristow, Virginia
20136-1217,
holder of 2,000 shares of Common Stock; Board of Pensions
of the Evangelical Lutheran Church in America, 800 Marquette
Avenue, Suite 1050, Minneapolis, Minnesota
55402-2892,
holder of 12,871 shares of Common Stock; Calvert Asset
Management Company, Inc., 4550 Montgomery Avenue, Bethesda,
Maryland 20814, representing four shareholders
Calvert Large Cap Value Fund, holder of 64,400 shares of
Common Stock, Summit Zenith Portfolio, holder of
137,800 shares of Common Stock, Summit Balanced Index
Portfolio, holder of 719 shares of Common Stock, and Summit
S&P 500 Index Portfolio, holder of 19,204 shares of
Common Stock; Catholic Health East, 3805 West Chester Pike,
Suite 100, Newtown Square, Pennsylvania
19073-2304,
holder of 150 shares of Common Stock; Catholic Healthcare
Partners, 615 Elsinore Place, Cincinnati, Ohio 45202, holder of
2,000 shares of Common Stock; Connecticut Retirement Plans
and Trust Funds, 55 Elm Street, Hartford, Connecticut
06106-1773,
holder of 169,619 shares of Common Stock; Providence Trust,
515 SW 24th Street, San Antonio, Texas
78207-4619,
holder of 5,700 shares of Common Stock; and Sisters of St.
Dominic of Caldwell New Jersey, 40 South Fullerton Avenue,
Montclair, New Jersey 07042, holder of 100 shares of Common
Stock, propose to submit the following resolution at the 2010
Annual Meeting of Stockholders.
Whereas: The International Energy Agency (IEA)
warned in its 2007 World Energy Outlook that urgent action
is needed if greenhouse gas [GHG] concentrations are to be
stabilized at a level that would prevent dangerous interference
with the climate system. In its 2009 report the IEA notes
that The scale and breadth of the energy challenge is
enormous far greater than many people realise. But
it can and must be met. The recession, by curbing the growth in
greenhouse-gas emissions, has made the task of transforming the
energy sector easier by giving us an unprecedented, yet
relatively narrow, window of opportunity to take action to
concentrate investment on low-carbon technology.
In October 2006, a report authored by former chief
economist of The World Bank, Sir Nicolas Stern, estimated that
climate change will cost between 5% and 20% of GDP if emissions
are not reduced, and that GHGs can be reduced at a cost of
approximately 1% of global economic growth.
U.S. power plants are responsible for nearly 40% of
the countrys carbon dioxide emissions, and 10% of global
carbon dioxide emissions.
Coal-burning power plants are responsible for 80% of
carbon dioxide emissions from all U.S. power plants and
Southern Co. is the second-largest emitter of
CO2,
the principal GHG linked to climate change, among
U.S. power generators.
Levels of carbon dioxide, which persists in the atmosphere
for over 100 years, are now higher than anytime in the past
400,000 years and they will continue to rise as long as
emissions from human activities continue.
26
President Obama and many members of Congress are pressing
on plans to limit greenhouse gas emissions; this will surely
impact the business of our Company regardless of the mechanisms.
AEP, the nations largest carbon dioxide emitter,
Entergy and Exelon have set total GHG emissions reduction
targets. Duke, Exelon, FPL, NRG, and others, through their
participation in the U.S. Climate Action Partnership, have
publicly stated that the U.S. should reduce its GHG
footprint by 60% to 80% from current levels by 2050. They have
endorsed adoption of mandatory federal policy to limit
CO2
emissions to provide economic and regulatory certainty needed
for major investments in our energy future.
Southern opposes mandatory regulation of
CO2
and other GHG emissions in favor of voluntary action. While our
company has added cleaner natural gas capacity, is investing in
renewable energy, has reduced the intensity of its
CO2
emissions, and looks to reduce GHG emissions by 80% by 2050
(Southern Company response to CDP6), we believe Southern still
needs to articulate a cohesive business plan for dealing with
climate risk and opportunity, and offer robust responses to the
financial, regulatory, and technology impacts of the climate
crisis.
RESOLVED: Shareholders request that the Board of
Directors report to shareholders actions the company would need
to take to reduce total
CO2
emissions, including quantitative goals for existing and
proposed plants based on current and emerging technologies, by
September 30, 2010. Such report shall omit proprietary
information and be prepared at reasonable cost.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE AGAINST
ITEM NO. 6 FOR THE FOLLOWING REASONS:
The Company is a leader in the industry in developing
technologies to reduce or eliminate carbon emissions in the
generation of electric energy. This is best evidenced by its
efforts to develop carbon capture and storage technologies and
to construct two new nuclear units at Plant Vogtle. Through
partnerships with the U.S. Department of Energy, the
Electric Power Research Institute, and the Southeast Regional
Carbon Sequestration Partnership, the Company is actively
engaged in developing and deploying technology to reduce
greenhouse gas emissions while ensuring that electricity remains
reliable and affordable. The Company manages and operates the
Department of Energys National Carbon Capture Center in
Alabama, which is scheduled to be fully operational this year.
For the past decade, the Company and the Department of Energy
have been developing cleaner, less expensive, more reliable
methods for power production from coal. This effort has resulted
in the creation of a new process of gasification called
Transport Integrated Gasification which not only matches, at a
minimum, the environmental performance of very efficient
gas-fired generation but also has the capability of capturing,
in a more cost efficient way, a significant portion of the
carbon dioxide emissions.
The Company does support greenhouse gas emissions reduction
targets and has created a number of reports disclosing its
actions related to carbon dioxide and other emissions. In
January 2009, the Company signed onto principles developed by
members of the Edison Electric Institute that outline a
legislative solution to address the reduction of greenhouse gas
emissions. These principles support near-term and mid-term
(10 20 years) reductions in emissions based on
the availability of technology and the use of energy efficiency,
renewable energy, and new nuclear, and support a reduction
target of 80% below current emissions levels by 2050. Also in
2009, the Company updated its report, Climate
Change A Summary of Southern Company Actions, on
specific current and long-term activities to address carbon
dioxide emissions. This report is updated on an annual basis.
This report is one of several produced by the Company,
including, in 2005, the Environmental Assessment: Report to
Shareholders, outlining options and actions the Company is
taking with regard to carbon dioxideand other emissions,
including an extensive review of carbon dioxideprice scenarios;
in 2006, and updated periodically since then, its Corporate
Responsibility Report, which includes data on emissions and
actions being undertaken to address those emissions; and in
2008, Energy Efficiency Regulatory Structures, discussing
the need for and the impacts of energy efficiency efforts as a
resource to meet growth and regulatory structures.
These reports are available either through the Companys
external website at www.southerncompany.com or by contacting
Melissa K. Caen, Assistant Corporate Secretary, Southern
Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308
and requesting a copy.
The vote needed to pass the proposed stockholders
resolution is a majority of the shares represented at the
meeting and entitled to vote.
27
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE AGAINST
ITEM NO. 6.
ITEM NO. 7
STOCKHOLDER PROPOSAL ON COAL COMBUSTION BYPRODUCTS
ENVIRONMENTAL REPORT
The Company has been advised that Green Century Capital
Management, Inc., 114 State Street, Suite 200, Boston,
Massachusetts 02109, holder of 120 shares of Common Stock,
proposes to submit the following resolution at the 2010 Annual
Meeting of Stockholders.
Whereas: Coal combustion waste (CCW) is a
by-product of burning coal that contains high concentrations of
arsenic, mercury, heavy metals and other toxins filtered out of
smokestacks by pollution control equipment. CCW is often stored
in landfills, impoundment ponds or abandoned mines. Over
130 million tons of CCW are generated each year in the U.S.
Coal combustion comprises a significant portion (68%) of
Southern Companys generation capacity.
The toxins in CCW have been linked to cancer, organ
failure, and other serious health problems. In October 2009, the
U.S. Environmental Protection Agency (EPA) published a
report finding that Pollutants in coal combustion
wastewater are of particular concern because they can occur in
large quantities (i.e., total pounds) and at high
concentrations...in discharges and leachate to groundwater and
surface waters.
The EPA has found evidence at over 60 sites in the
U.S. that CCW has polluted ground and surface waters.
Recent reports by the New York Times and others
have drawn attention to CCWs impact on the nations
waterways, as a result of leaking CCW storage sites or direct
discharge into surrounding rivers and streams.
The Tennessee Valley Authoritys (TVA)
1.1 billion gallon CCW spill in December 2008 that covered
over 300 acres in eastern Tennessee with toxic sludge
highlights the serious environmental risks associated with CCW.
TVA estimates a total cleanup cost of $1.2 billion. This
figure does not include the legal claims that have arisen in the
spills aftermath.
Our company also re-uses a significant portion of its CCW.
While dry CCW has beneficial re-uses, such as in concrete and
pavement, it can also pose public health and environmental risks
in the dry form.
The EPA plans to determine by the end of 2009 whether
certain power plant by-products such as coal ash should be
treated as hazardous waste, which would subject CCW to stricter
regulations.
The EPA has identified over 580 CCW impoundment facilities
around the country. At least 49 of these have been rated by the
National Inventory of Dams (NID) as high hazard
potential sites, where a dam breach would likely result in
a loss of human life and significant environmental consequences.
According to our companys filings with the EPA, our
company operates at least 18 CCW impoundments. One of these
ponds, operated by Georgia Power, has been labeled high
hazard potential by the NID.
Our company has withheld information about inspections and
size of its ponds as confidential, despite disclosure of
inspection information by all other responding companies,
keeping shareholders in the dark about possible risks.
RESOLVED: Shareholders request that the Board
prepare a report on the companys efforts, above and beyond
current compliance, to reduce environmental and health hazards
associated with coal combustion waste, and how those efforts may
reduce legal, reputational and other risks to the companys
finances and operations. This report should be available to
shareholders by August 2010, be prepared at reasonable cost, and
omit confidential information such as proprietary data or legal
strategy.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE AGAINST
ITEM NO. 7 FOR THE FOLLOWING REASONS:
The Companys affiliates have an extensive system in place
to ensure the safe and proper management of coal combustion
byproducts (CCBs). In addition, a significant amount of CCBs
from the Companys affiliates coal-based power
generation plants, including coal ash and gypsum, is recycled
for safe and beneficial uses such as concrete production and
road building. The Company has prepared a report to provide an
overview of its affiliates production and management of
CCBs from electricity generation. The report includes relevant
information on the Companys affiliates operations
related to CCBs, as well as the broad range of steps taken to
ensure that the priorities of public safety and the security of
the Companys affiliates
28
plants are met. The report details the Companys
affiliates operations, including how the CCBs are
generated, the procedures for safe handling, the beneficial use
market, and research efforts. The Company has posted the report
on its website. The Company has also provided extensive,
detailed information about its affiliates management of
CCBs to the U.S. Environmental Protection Agency (EPA).
This information is being released to the public on the EPA
website
(http://www.epa.gov
/waste/nonhaz/industrial/special/fossil/surveys/index.htm).
Additionally, the Company posts on its website its Corporate
Responsibility Report which was created in 2006 and is
updated periodically with new information. The Corporate
Responsibility Report also includes a section on CCBs,
including information on the management and beneficial use of
CCBs. CCBs are recycled and used as an ingredient in common,
everyday products. The success of the Companys
affiliates beneficial use programs reduces landfill
obligations by more than 1.5 million tons annually. The
beneficial use of CCBs has many associated environmental
benefits, including a reduction in energy consumption,
greenhouse gases, need for additional landfill space, and raw
material consumption. The characteristics of CCBs enable
beneficial uses and management to be undertaken safely. The
concentration of metals in CCBs that occurs naturally in coal in
trace amounts is not comparable to levels found in other
substances that are required to be regulated as hazardous. While
the Companys affiliates have focused recent efforts on the
beneficial use of CCBs, they have safely managed the remaining
byproducts at their respective plants for decades. The
Companys affiliates have a robust program in place to
ensure the safety and integrity of dams and dikes at
on-site
surface impoundments. They are inspected at least every week by
trained plant personnel and inspected at least every year by
professional dam safety engineers. The Company has managed
nearly $500 million in research and development over the
past decade, including several projects to find new and
innovative ways to beneficially use CCBs.
The Company-produced reports are available either through the
Companys external website at www.southerncompany.com or by
contacting Melissa K. Caen, Assistant Corporate Secretary,
Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta,
Georgia 30308 and requesting a copy.
The vote needed to pass the proposed stockholders
resolution is a majority of the shares represented at the
meeting and entitled to vote.
THE BOARD
OF DIRECTORS RECOMMENDS A VOTE AGAINST
ITEM NO. 7.
29
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
2009 Annual Report to Stockholders attached hereto as
Appendix C 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 issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Audit Committee
has discussed with the independent registered public accounting
firm the matters that are required to be discussed by Statement
on Auditing Standards No. 61, as amended (American
Institute of Certified Public Accountants, Professional
Standards, Vol. 1, AU Section 380), as adopted by the
Public Company Accounting Oversight Board (PCAOB) in
Rule 3200T. In addition, the Audit Committee has discussed
with the independent registered public accounting firm its
independence from management and the Company as required under
rules of the PCAOB and has received the written disclosures and
letter from the independent registered public accounting firm
required by the rules of the PCAOB. The Audit Committee also has
considered whether the independent registered public accounting
firms provision of non-audit services to the Company is
compatible with maintaining the firms independence.
The Audit Committee discussed the overall scopes 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 Committee held 10
meetings during 2009.
In reliance on the reviews and discussions referred to above,
the Audit Committee recommended to the Board of Directors (and
the Board approved) that the audited consolidated financial
statements be included in the Companys Annual Report on
Form 10-K
for the year ended December 31, 2009 and filed with the
SEC. The Audit Committee also reappointed Deloitte &
Touche as the Companys independent registered public
accounting firm for 2010. Stockholders will be asked to ratify
that selection at the Annual Meeting of Stockholders.
Members of the Audit Committee:
William G. Smith, Jr., Chair
Jon A. Boscia
Warren A. Hood, Jr.
30
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 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
(In thousands)
|
|
|
Audit Fees(a)
|
|
$
|
11,368
|
|
|
$
|
12,439
|
|
Audit-Related Fees(b)
|
|
|
546
|
|
|
|
900
|
|
Tax Fees
|
|
|
0
|
|
|
|
0
|
|
All Other Fees
|
|
|
0
|
|
|
|
0
|
|
|
Total
|
|
$
|
11,914
|
|
|
$
|
13,339
|
|
|
|
|
|
(a) |
|
Includes services performed in connection with financing
transactions. |
|
(b) |
|
Includes benefit plan and other non-statutory audit services and
accounting consultations in both 2009 and 2008. |
The Audit Committee has adopted a Policy on Engagement of the
Independent Auditor for Audit and Non-Audit Services (see
Appendix B) that includes requirements for the Audit
Committee to pre-approve services provided by
Deloitte & Touche. This policy was initially adopted
in July 2002 and, since that time, all services included in the
chart above have been pre-approved by the Audit Committee.
31
Executive
Compensation
COMPENSATION DISCUSSION AND ANALYSIS (CD&A)
GUIDING
PRINCIPLES AND POLICIES
The Companys executive compensation program is based on a
philosophy that total executive compensation must be competitive
with the companies in our industry, must be tied to and motivate
our executives to meet our short- and long-term performance
goals, must foster and encourage alignment of executive
interests with the interests of our stockholders and our
customers, and must not encourage excessive risk-taking. The
program generally is designed to motivate all employees,
including executives, to achieve operational excellence and
financial goals while maintaining a safe work environment.
Our executive compensation program places significant focus on
rewarding performance. The program is performance-based in
several respects:
|
|
|
Our actual earnings per share (EPS) and business unit
performance, which includes return on equity (ROE) or net
income, compared to target performance levels established early
in the year, determine the actual payouts under the short-term
(annual) performance-based compensation program (Performance Pay
Program).
|
|
|
Common Stock price changes result in higher or lower ultimate
values of stock options.
|
|
|
Our dividend payout and total shareholder return compared to
those of our industry peers lead to higher or lower payouts
under the Performance Dividend Program (performance dividends).
|
In support of our performance-based pay philosophy, we have no
general employment contracts with our named executive officers
or guaranteed severance, except upon a change in control.
Our
pay-for-performance
principles apply not only to the named executive officers, but
to thousands of employees. Our Performance Pay Program covers
almost all of our nearly 26,000 employees. Our stock
options and performance dividends cover approximately
7,000 employees. These programs engage our people in our
business, which ultimately is good not only for them, but for
our customers and our stockholders.
OVERVIEW
OF EXECUTIVE COMPENSATION COMPONENTS
Our executive compensation program has several components, each
of which plays a different role. The chart below discusses the
intended role of each material pay component, what it rewards,
and why we use it. Following the chart is additional information
that describes how we made 2009 pay decisions.
|
|
|
|
|
|
|
Intended Role and What the Element
|
|
|
Pay Element
|
|
Rewards
|
|
Why We Use the Element
|
|
|
Base Salary
|
|
Base salary is pay for competence in the executive role, with a
focus on scope of responsibilities.
|
|
Market practice.
Provides a threshold level of cash compensation for job performance.
|
|
Annual Performance-Based Compensation: Performance Pay
Program
|
|
The Performance Pay Program rewards achievement of operational,
EPS, and business unit financial goals.
|
|
Market practice.
Focuses attention on achievement of short-term goals that ultimately work to fulfill our mission to customers and lead to increased stockholder value in the long term.
|
|
32
|
|
|
|
|
|
|
Intended Role and What the Element
|
|
|
Pay Element
|
|
Rewards
|
|
Why We Use the Element
|
|
|
Long-Term Performance-Based Compensation: Stock Options
|
|
Stock options reward price increases in Common Stock over the
market price on the date of grant, over a 10-year term.
|
|
Market practice.
Performance-based compensation.
Aligns executives interests with those of stockholders.
|
|
Long-Term Performance-Based Compensation: Performance
Dividends
|
|
Performance dividends provide cash compensation dependent on the
number of stock options held at year end, the Common Stock
dividends paid during the year, and the four-year total
shareholder return versus industry peers.
|
|
Market practice.
Performance-based compensation.
Enhances the value of stock options and focuses executives on maintaining a significant dividend yield for stockholders.
Aligns executives interests with stockholders interests since payouts are dependent on the returns realized by our stockholders versus those of our industry peers.
|
|
Retirement Benefits
|
|
The Southern Company Deferred Compensation Plan provides the opportunity to defer to future years up to 50% of base salary and all or part of performance-based compensation, except stock options, in either a prime interest rate or Common Stock account.
Executives participate in employee benefit plans available to all employees of the Company, including a 401(k) savings plan and the funded Southern Company Pension Plan (Pension Plan).
The Supplemental Benefit Plan counts pay, including deferred salary, ineligible to be counted under the Pension Plan and the 401(k) plan due to Internal Revenue Service rules.
The Supplemental Executive Retirement Plan counts annual performance-based pay above 15% of base salary for pension purposes.
|
|
Market practice.
Permitting compensation deferral is a cost-effective method of providing additional cash flow to the Company while enhancing the retirement savings of executives.
The purpose of these supplemental plans is to eliminate the effect of tax limitations on the payment of retirement benefits.
Represents an important component of competitive market-based compensation in both our peer group and generally.
|
|
33
|
|
|
|
|
|
|
Intended Role and What the Element
|
|
|
Pay Element
|
|
Rewards
|
|
Why We Use the Element
|
|
|
Perquisites and Other Personal Benefits
|
|
Personal financial planning maximizes the perceived value of our executive compensation program to executives and allows them to focus on Company operations.
Home security systems lower the risk of harm to executives.
Club memberships are provided primarily for business use.
Limited personal use of corporate-owned aircraft associated with business travel.
Tax gross-ups are not provided on any perquisites except relocation benefits.
|
|
Perquisites benefit both the Company and executives, at low cost
to the Company.
|
|
Post-Termination Pay
|
|
Change-in-control agreements provide severance pay, accelerated
vesting, and payment of short- and long-term performance-based
compensation upon a change in control of the Company coupled
with involuntary termination not for cause or a voluntary
termination for Good Reason.
|
|
Market practice.
Providing protections to officers upon a change in control minimizes disruption during a pending or anticipated change in control.
Payment and vesting occur only upon the occurrence of both an actual change in control and loss of the executives position.
|
|
34
MARKET
DATA
For the named executive officers, the Compensation Committee
reviews compensation data from large, publicly-owned electric
and gas utilities. The data was developed and analyzed by Towers
Perrin, the compensation consultant retained by the Compensation
Committee. The companies included each year in the primary peer
group are those whose data is available through Towers
Perrins database. Those companies are drawn from this list
of primarily regulated utilities of $2 billion in revenues
and up.
|
|
|
|
|
|
|
AGL Resources Inc.
|
|
El Paso Corporation
|
|
PG&E Corporation
|
Allegheny Energy, Inc.
|
|
Entergy Corporation
|
|
Pinnacle West Capital Corporation
|
Alliant Energy Corporation
|
|
EPCO
|
|
PPL Corporation
|
Ameren Corporation
|
|
Exelon Corporation
|
|
Progress Energy, Inc.
|
American Electric Power Company, Inc.
|
|
FirstEnergy Corp.
|
|
Public Service Enterprise Group Inc.
|
Atmos Energy Corporation
|
|
FPL Group, Inc.
|
|
Puget Energy, Inc.
|
Calpine Corporation
|
|
Integrys Energy Company, Inc.
|
|
Reliant Energy, Inc.
|
CenterPoint Energy, Inc.
|
|
MDU Resources, Inc.
|
|
Salt River Project
|
CMS Energy Corporation
|
|
Mirant Corporation
|
|
SCANA Corporation
|
Consolidated Edison, Inc.
|
|
New York Power Authority
|
|
Sempra Energy
|
Constellation Energy Group, Inc.
|
|
Nicor, Inc.
|
|
Southern Union Company
|
CPS Energy
|
|
Northeast Utilities
|
|
Spectra Energy
|
DCP Midstream
|
|
NRG Energy, Inc.
|
|
TECO Energy
|
Dominion Resources Inc.
|
|
NSTAR
|
|
Tennessee Valley Authority
|
Duke Energy Corporation
|
|
NV Energy, Inc.
|
|
The Williams Companies, Inc.
|
Dynegy Inc.
|
|
OGE Energy Corp.
|
|
Wisconsin Energy Corporation
|
Edison International
|
|
Pepco Holdings, Inc.
|
|
Xcel Energy Inc.
|
|
|
The Company is one of the largest utility companies in the
United States based on revenues and market capitalization, and
its largest business units are some of the largest in the
industry as well. For that reason, the consultant size-adjusts
the survey market data in order to fit it to the scope of our
business.
As an additional reference, the Compensation Committee reviewed
the compensation disclosed for the chief executive officers of
the 24 largest utilities in terms of revenue. The consultant
obtained this information from each of the following
companies 2009 proxy filings.
|
|
|
|
Ameren Corporation
|
|
FirstEnergy Corp.
|
American Electric Power Company, Inc.
|
|
FPL Group, Inc.
|
CenterPoint Energy, Inc.
|
|
Integrys Energy Company, Inc.
|
CMS Energy Corporation
|
|
Nisource Inc.
|
Consolidated Edison, Inc.
|
|
Northeast Utilities
|
Constellation Energy Group, Inc.
|
|
Pepco Holdings, Inc.
|
Dominion Resources Inc.
|
|
PG&E Corporation
|
DTE Energy
|
|
PPL Corporation
|
Duke Energy Corporation
|
|
Progress Energy, Inc.
|
Edison International
|
|
Public Service Enterprise Group, Inc.
|
Entergy Corporation
|
|
Sempra Energy
|
Exelon Corporation
|
|
Xcel Energy Inc.
|
|
In using this market data, market is defined as the
size-adjusted 50th percentile of the survey data, with a
focus on pay opportunities at target performance (rather than
actual plan payouts). The Company specifically looks at the
market data for chief executive officer positions and other
positions in terms of scope of responsibilities that most
closely resemble the positions held by the named executive
officers. Based on that data, the Company recommends to the
Compensation Committee a total target compensation opportunity
for each named executive officer. Total target compensation
opportunity
35
is the sum of base salary, annual performance-based compensation
at the target performance level, and stock option awards with
associated performance dividends at a target value. Actual
compensation paid may be more or less than the total target
compensation opportunity based on actual performance above or
below target performance levels. As a result, our compensation
program is designed to result in payouts that are
market-appropriate given our performance for the year or period.
The Company did not target a specified weight for base salary or
annual or long-term performance-based compensation as a
percentage of total target compensation opportunities, nor did
amounts realized or realizable from prior compensation serve to
increase or decrease 2009 compensation amounts. Total target
compensation opportunities for senior management as a group are
managed to be at the median of the market for companies of our
size and in our industry. At the beginning of 2009, all of the
named executive officers were below the median of the
above-described market data. The Compensation Committee adjusted
the target long-term performance-based compensation value to
bring the total target compensation levels to the median of the
market. Except for Mr. Ratcliffe, the total target
compensation levels of the named executive officers increased in
2009. The decrease in Mr. Ratcliffes total target
compensation level was due primarily to the change in valuation
of stock options as described below. With the exception of a
base salary increase for Mr. Bowers, as described below, no
other changes to pay components were made in 2009. The total
target compensation opportunity established in 2009 for each
named executive officer is shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
Long-Term
|
|
Total Target
|
|
|
|
|
Performance-Based
|
|
Performance-Based
|
|
Compensation
|
|
|
Salary
|
|
Compensation
|
|
Compensation
|
|
Opportunity
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
1,129,467
|
|
|
|
1,129,467
|
|
|
|
4,913,181
|
|
|
|
7,172,115
|
|
|
W. P. Bowers
|
|
|
599,004
|
|
|
|
449,253
|
|
|
|
1,347,756
|
|
|
|
2,396,013
|
|
|
T. A. Fanning
|
|
|
664,685
|
|
|
|
498,514
|
|
|
|
1,256,252
|
|
|
|
2,419,451
|
|
|
M. D. Garrett
|
|
|
695,402
|
|
|
|
521,552
|
|
|
|
1,279,539
|
|
|
|
2,496,493
|
|
|
C. D. McCrary
|
|
|
662,242
|
|
|
|
496,681
|
|
|
|
1,185,412
|
|
|
|
2,344,335
|
|
|
For purposes of comparing the value of our compensation program
to the market data, stock options are valued at 5.7%, and
performance dividend targets at 10%, of the average daily Common
Stock price for the year preceding the grant, both of which
represent risk-adjusted present values on the date of grant and
are consistent with the methodologies used to develop the market
data. For the 2009 grant of stock options and the performance
dividend targets established for the
2009-2012
performance-measurement period, this value was $4.94 per stock
option granted. In the long-term incentive column, 36% of the
value shown is attributable to stock options and 64% is
attributable to performance dividends. The value of stock
options, with the associated performance dividends, declined
from 2008. In 2008 and 2009, the value of the dividend
equivalents was 10% of the Common Stock price on the stock
option grant date, but the value of the stock option declined
from 12% to 5.7%. In 2008, the performance dividends represented
45% of the long-term incentive target value and stock options
represented 55% of that value. More information on how stock
options are valued is reported in the Grants of Plan-Based Award
table and the information accompanying it.
As discussed above, the Compensation Committee targets total
target compensation opportunities for senior executives as a
group at market. Therefore, some executives may be paid somewhat
above and others somewhat below market. This practice allows for
minor differentiation based on time in the position, scope of
responsibilities, and individual performance. The differences in
the total pay opportunities for each named executive officer are
based almost exclusively on the differences indicated by the
market data for persons holding similar positions. The average
total target compensation opportunities for the named executive
officers for 2009 were at the median of the market data
described above. Because of the use of market data from a large
number of peer companies for positions that are not identical in
terms of scope of responsibility from company to company, we do
not consider any slight differences material and continue to
believe that our compensation program is market-appropriate.
Generally, we consider compensation to be within an appropriate
range if it is not more or less than 10% of the applicable
market data.
In 2008, Towers Perrin analyzed the level of actual payouts, for
2007 performance, under the annual Performance Pay Program to
the named executive officers relative to performance versus our
peer companies to provide a check on the Companys
goal-setting process. The findings from the analyses were used
in establishing performance goals and the
36
associated range of payouts for goal achievement for 2009. That
analysis was updated in 2009 for 2008 performance, and those
findings were used in establishing goals for 2010.
In 2008, the Compensation Committee received a detailed
comparison of the Companys executive benefits program to
the benefits of a group of other large utilities and general
industry companies. The results indicated that overall the
Companys executive benefits program was at market. Because
this data does not change significantly year over year, the
study is only updated every few years.
DESCRIPTION
OF KEY COMPENSATION COMPONENTS
2009 Base
Salary
Consistent with the broad-based compensation program for 2009,
the Compensation Committee did not make any base salary
adjustments for the named executive officers, except for
Mr. Bowers. Because Mr. Bowers base salary was
more than 10% below the median of the market data described
above, Mr. Ratcliffe recommended a 6% salary increase,
which was approved by the Compensation Committee.
2009
Performance-Based Compensation
This section describes our performance-based compensation
program in 2009. The Compensation Committee approved changes to
that program in 2009, to be effective in 2010. These changes are
described in the last section of this CD&A entitled 2010
Executive Compensation Program Changes.
Achieving Operational and Financial Goals Our
Guiding Principle for Performance-Based Compensation
Our number one priority is to provide our customers outstanding
reliability and superior service at low prices while achieving a
level of financial performance that benefits our stockholders in
the short and long term.
In 2009, we strove for and rewarded:
|
|
|
Continued industry-leading reliability and customer
satisfaction, while maintaining our low retail prices relative
to the national average; and
|
|
|
Meeting energy demand with the best economic and environmental
choices.
|
In 2009, we also focused on and rewarded:
|
|
|
EPS growth;
|
|
|
ROE in the top quartile of comparable electric utilities;
|
|
|
Dividend growth;
|
|
|
Long-term, risk-adjusted total shareholder return; and
|
|
|
Financial integrity an attractive risk-adjusted
return, sound financial policy, and a stable A
credit rating.
|
The performance-based compensation program is designed to
encourage achievement of these goals.
Mr. Ratcliffe, with the assistance of our Human Resources
staff, recommended to the Compensation Committee program design
and award amounts for senior executives, including the named
executive officers.
2009 Annual Performance Pay Program
Program
Design
The Performance Pay Program is the Companys annual
performance-based compensation program. Most employees of the
Company, including the named executive officers, are
participants for a total of almost 26,000 participants.
The performance measured by the program uses goals set at the
beginning of each year by the Compensation Committee.
37
An illustration of the annual Performance Pay Program goal
structure for 2009 is provided below.
|
|
|
Operational goals for 2009 were safety, customer satisfaction,
plant availability, transmission and distribution system
reliability, and inclusion. Each of these operational goals is
explained in more detail under Goal Details below. The result of
all operational goals is averaged and multiplied by the bonus
impact of the EPS and business unit financial goals. The amount
for each goal can range from 0.90 to 1.10 or can be 0.00 if a
threshold performance level is not achieved as more fully
described below. The level of achievement for each operational
goal is determined and the results are averaged. Each of our
business units has operational goals. For Messrs. Garrett
and McCrary, the payout is adjusted up or down based on the
operational goal results for Georgia Power and Alabama Power,
respectively. For Messrs. Ratcliffe, Bowers, and Fanning,
it is calculated using the corporate-wide weighted average of
the operational goal results.
|
|
|
EPS is weighted at 50% of the financial goals. EPS is defined as
earnings from continuing operations divided by average shares
outstanding during the year. The EPS performance measure is
applicable to all participants in the Performance Pay Program.
|
|
|
Business unit financial performance is weighted at 50% of the
financial goals. For our traditional utility operating companies
(Alabama Power, Georgia Power, Gulf Power, and Mississippi
Power), the business unit financial performance goal is ROE,
which is defined as the operating companys net income
divided by average equity for the year. For each of our other
business units, we establish financial performance measures that
are tailored to such business unit.
|
For Messrs. Garrett and McCrary, the annual Performance Pay
Program payout is calculated using the ROE for Georgia Power and
Alabama Power, respectively. For Messrs. Ratcliffe, Bowers,
and Fanning, it is calculated using a corporate-wide weighted
average of all the business unit financial performance goals,
including primarily each traditional operating companys
ROE. The Compensation Committee may make adjustments, both
positive and negative, to goal achievement for purposes of
determining payouts. Such adjustments include the impact of
items considered non-recurring or outside of normal operations
or not anticipated in the business plan when the earnings goal
was established and of sufficient magnitude to warrant
recognition. The Compensation Committee made an adjustment in
2009 to eliminate the effect of a $202 million charge
($0.25 per share) to earnings taken in 2009. The charge related
to the settlement agreement with MC Asset Recovery, LLC (MCAR)
to resolve an action which arose out of the bankruptcy
proceeding of Mirant Corporation, a former subsidiary of the
Company until its spin-off in April 2001. The settlement
included an agreement by the Company to pay MCAR
$202 million, which was paid in mid-2009. This adjustment
increased the average payout for 2009 performance by
approximately 30%.
Under the terms of the program, no payout can be made if the
Companys current earnings are not sufficient to fund the
Common Stock dividend at the same level or higher than the prior
year.
Goal
Details
Operational Goals:
Customer Satisfaction The Company uses customer
satisfaction surveys to evaluate its performance. The survey
results provide an overall ranking for each traditional
operating company, as well as a ranking for each customer
segment: residential, commercial, and industrial.
38
Reliability Transmission and distribution system
reliability performance is measured by the frequency and
duration of outages. Performance targets for reliability are set
internally based on historical performance, expected weather
conditions, and expected capital expenditures.
Availability Peak season equivalent forced outage
rate is an indicator of availability and efficient generation
fleet operations during the months when generation needs are
greatest. The rate is calculated by dividing the number of hours
of forced outages by total generation hours.
Safety The Companys Target Zero program is
focused on continuous improvement in having a safe work
environment. The performance is measured by the Occupational
Safety and Health Administration recordable incident rate.
Inclusion/Diversity The inclusion program seeks to
improve our inclusive workplace. This goal includes measures for
work environment (employee satisfaction survey), representation
of minorities and females in leadership roles, and supplier
diversity.
Southern Company capital expenditures gate or
threshold goal We strived to manage total capital
expenditures, excluding nuclear fuel, for the participating
business units at or below $4.5 billion. If the capital
expenditure target is exceeded, total operational goal
performance is capped at 0.90 for all business units, regardless
of the actual operational goal results. Adjustments to the goal
may occur due to significant events not anticipated in the
business plan established early in 2009, such as acquisitions or
disposition of assets, new capital projects, and other events.
The ranges of performance levels established for the operational
goals are detailed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
Level of
|
|
Customer
|
|
|
|
|
|
|
|
|
|
Performance
|
|
Satisfaction
|
|
Reliability
|
|
Availability(%)
|
|
|
Safety
|
|
Inclusion
|
|
|
Maximum (1.10)
|
|
Top quartile for
each customer
segment
|
|
Improve historical performance
|
|
|
2.00
|
|
|
0.62 or top quartile
|
|
Significant improvement
|
|
Target (1.00)
|
|
Top quartile
overall
|
|
Maintain historical performance
|
|
|
2.75
|
|
|
0.988
|
|
Improve
|
|
Threshold (0.90)
|
|
2nd quartile
overall
|
|
Below
historical performance
|
|
|
3.75
|
|
|
1.373
|
|
Below expectations
|
|
0 Trigger
|
|
At or below median
|
|
Significant issues
|
|
|
6.00
|
|
|
Each quarter at threshold or below
|
|
Significant issues
|
|
EPS and Business Unit Financial Performance:
The range of EPS and ROE goals for 2009 is shown below. ROE
goals vary from the allowed retail ROE range due to state
regulatory accounting requirements, wholesale activities, other
non-jurisdictional revenues and expenses, and other activities
not subject to state regulation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payout Below
|
|
|
|
|
|
|
|
|
Payout Factor at
|
|
Threshold for
|
|
|
EPS, excluding
|
|
|
|
|
|
Associated Level of
|
|
Operational
|
Level of
|
|
MCAR
|
|
|
|
Payout
|
|
Operational Goal
|
|
Goal
|
Performance
|
|
Settlement Impact
|
|
ROE
|
|
Factor
|
|
Achievement
|
|
Achievement
|
|
|
Maximum
|
|
$
|
2.50
|
|
|
|
13.7
|
%
|
|
|
2.00
|
|
|
|
2.20
|
|
|
|
0.00
|
|
|
Target
|
|
$
|
2.375
|
|
|
|
12.7
|
%
|
|
|
1.00
|
|
|
|
1.00
|
|
|
|
0.00
|
|
|
Threshold
|
|
$
|
2.25
|
|
|
|
11.00
|
%
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
0.00
|
|
|
Below threshold
|
|
<$
|
2.25
|
|
|
|
<11.00
|
%
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
39
2009
Achievement
Each named executive officer had a target Performance Pay
Program opportunity set by the Compensation Committee at the
beginning of 2009. Targets are set as a percentage of base
salary. Mr. Ratcliffes target was set at 100%. For
the other named executive officers, it was set at 75%. Actual
payouts were determined by adding the payouts derived from EPS
and business unit financial performance goal achievement for
2009 and multiplying that sum by the result of the operational
goal achievement. The gate goal target was not exceeded and
therefore did not affect payouts. Actual 2009 goal achievement
is shown in the following table. The EPS result shown in the
table is adjusted for the MCAR settlement charge taken in 2009,
as described above. Therefore, payouts were determined using EPS
performance results that differed from the results reported in
the Companys financial statements in the 2009 Annual
Report attached as Appendix C to this Proxy Statement
(Financial Statements). EPS, as determined in accordance with
accounting principles generally accepted in the United States
and as reported in the Financial Statements, was $2.07 per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPS,
|
|
|
|
|
|
|
|
Business Unit
|
|
|
|
|
|
|
|
|
|
Operational
|
|
|
excluding
|
|
|
EPS Goal
|
|
|
|
|
Financial
|
|
|
Total Weighted
|
|
|
Total
|
|
|
|
Goal
|
|
|
MCAR
|
|
|
Performance
|
|
|
|
|
Performance
|
|
|
Financial
|
|
|
Payout
|
|
|
|
Multiplier
|
|
|
Settlement
|
|
|
Factor
|
|
|
Business Unit
|
|
Factor
|
|
|
Performance
|
|
|
Factor
|
|
Name
|
|
(A)
|
|
|
Impact
|
|
|
(50% Weight)
|
|
|
Financial Performance
|
|
(50% Weight)
|
|
|
Factor (B)
|
|
|
(A x B)
|
|
|
|
D. M. Ratcliffe
|
|
|
1.08
|
|
|
$
|
2.32
|
|
|
|
0.57
|
|
|
Corporate-wide weighted average
|
|
|
0.90
|
|
|
|
0.73
|
|
|
|
0.79
|
|
|
W. P. Bowers
|
|
|
1.08
|
|
|
$
|
2.32
|
|
|
|
0.57
|
|
|
Corporate-wide weighted average
|
|
|
0.90
|
|
|
|
0.73
|
|
|
|
0.79
|
|
|
T. A. Fanning
|
|
|
1.08
|
|
|
$
|
2.32
|
|
|
|
0.57
|
|
|
Corporate-wide weighted average
|
|
|
0.90
|
|
|
|
0.73
|
|
|
|
0.79
|
|
|
M. D. Garrett
|
|
|
1.06
|
|
|
$
|
2.32
|
|
|
|
0.57
|
|
|
11.01% ROE
|
|
|
0.01
|
|
|
|
0.29
|
|
|
|
0.30
|
|
|
C. D. McCrary
|
|
|
1.09
|
|
|
$
|
2.32
|
|
|
|
0.57
|
|
|
13.27% ROE
|
|
|
1.57
|
|
|
|
1.07
|
|
|
|
1.17
|
|
|
Note that the Total Payout Factor may vary from the Total
Weighted Financial Performance Factor multiplied by the
Operational Goal Multiplier due to rounding. To calculate the
Performance Pay Program amount, the target opportunity is
multiplied by the Total Payout Factor.
Except for performance at Alabama Power, actual performance, as
adjusted, was below the target performance levels established by
the Compensation Committee in early 2009; therefore, the payout
levels for all of the named executive officers, except
Mr. McCrary, were below the target pay opportunities that
were established. More information on how the target pay
opportunities are established is provided under the Market Data
section in this CD&A.
The table below shows the pay opportunity set in early 2009 for
the annual Performance Pay Program payout at target-level
performance and the actual payout based on the actual
performance, as adjusted, shown above.
|
|
|
|
|
|
|
|
|
|
|
Target Annual
|
|
Actual Annual
|
|
|
Performance Pay Program
|
|
Performance Pay Program
|
Name
|
|
Opportunity ($)
|
|
Payout ($)
|
|
|
D. M. Ratcliffe
|
|
|
1,129,467
|
|
|
|
892,279
|
|
|
W. P. Bowers
|
|
|
449,253
|
|
|
|
354,910
|
|
|
T. A. Fanning
|
|
|
498,514
|
|
|
|
393,826
|
|
|
M. D. Garrett
|
|
|
521,552
|
|
|
|
156,466
|
|
|
C. D. McCrary
|
|
|
496,681
|
|
|
|
581,117
|
|
|
Stock Options
Stock options are granted annually and were granted in 2009 to
the named executive officers and about 7,000 other employees.
Options have a
10-year
term, vest over a three-year period, fully vest upon retirement
or termination of employment following a change in control, and
expire at the earlier of five years from the date of retirement
or the end of the
10-year
term. The Compensation Committee changed the stock option
vesting provisions associated with retirement for
40
stock options granted in 2009 to the executive officers of the
Company, including the named executive officers. For the grants
made in 2009, unvested options are forfeited if the executive
officer retires from the Company and accepts a position with a
peer company within two years of retirement. The Compensation
Committee made this change to provide more retention value to
the stock option awards, to provide an inducement to not seek a
position with a peer company, and to limit the post-termination
compensation of any executive officer who accepts a position
with a peer company.
As described in the Market Data section above, the Compensation
Committee established a target long-term performance-based
compensation value for each named executive officer. The number
of stock options granted, with associated performance dividends,
was determined by dividing that long-term value by the value of
a stock option with associated performance dividends. The value
of each stock option was derived using the Black-Scholes stock
option pricing model. The assumptions used in calculating that
amount are discussed in Note 8 to the Financial Statements.
For 2009, the Black-Scholes value on the grant date was $1.80
per stock option. As described in the Market Data section above,
the value of the associated performance dividends was $3.14 per
stock option which was 10% of the Common Stock price on the
grant date. Therefore, the target value of each stock option,
with associated performance dividends, was $4.94 per stock
option. The calculation of the 2009 stock option grants for the
named executive officers is shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
|
|
Value Per
|
|
Number of Stock
|
Name
|
|
Value ($)
|
|
Stock Option ($)
|
|
Options Granted
|
|
|
D. M. Ratcliffe
|
|
|
4,913,181
|
|
|
|
4.94
|
|
|
|
994,571
|
|
|
W. P. Bowers
|
|
|
1,347,756
|
|
|
|
4.94
|
|
|
|
272,825
|
|
|
T. A. Fanning
|
|
|
1,256,252
|
|
|
|
4.94
|
|
|
|
254,302
|
|
|
M. D. Garrett
|
|
|
1,279,539
|
|
|
|
4.94
|
|
|
|
259,016
|
|
|
C. D. McCrary
|
|
|
1,185,412
|
|
|
|
4.94
|
|
|
|
239,962
|
|
|
More information about the stock option program is contained in
the Grants of Plan-Based Awards table and the information
accompanying it.
Performance Dividends
All option holders, including the named executive officers, can
receive performance-based dividend equivalents on stock options
held at the end of the year. Performance dividends can range
from 0% to 100% of the Common Stock dividend paid during the
year per option held at the end of the year. Actual payout will
depend on our total shareholder return over a four-year
performance-measurement period compared to a group of other
electric and gas utility companies. The peer group is determined
at the beginning of each four-year performance-measurement
period. The peer group varies from the Market Data peer group
due to the timing and criteria of the peer selection process.
The peer group for performance dividends is set by the
Compensation Committee at the beginning of the four-year
performance-measurement period. However, despite these timing
differences, there is substantial overlap in the companies
included.
Total shareholder return is calculated by measuring the ending
value of a hypothetical $100 invested in each companys
common stock at the beginning of each of 16 quarters. In the
final year of the performance-measurement period, the
Companys ranking in the peer group is determined at the
end of each quarter and the percentile ranking is multiplied by
the actual Common Stock dividend paid in that quarter. To
determine the total payout per stock option held at the end of
the performance-measurement period, the four quarterly amounts
earned are added together.
No performance dividends are paid if the Companys earnings
are not sufficient to fund a Common Stock dividend at least
equal to that paid in the prior year.
41
2009
Payout
The peer group used to determine the 2009 payout for the
2006-2009
performance-measurement period consisted of utilities with
revenues of $1.2 billion or more with regulated revenues of
60% or more. Those companies are listed below.
|
|
|
|
|
|
Allegheny Energy, Inc.
|
|
Entergy Corporation
|
|
Pinnacle West Capital Corp.
|
Alliant Energy Corporation
|
|
Exelon Corporation
|
|
Progress Energy, Inc.
|
Ameren Corporation
|
|
FPL Group, Inc.
|
|
SCANA Corporation
|
American Electric Power Company, Inc.
|
|
NiSource Inc.
|
|
Sempra Energy
|
CenterPoint Energy, Inc.
|
|
Northeast Utilities
|
|
Westar Energy Corporation
|
CMS Energy Corporation
|
|
NSTAR
|
|
Wisconsin Energy Corporation
|
Consolidated Edison, Inc.
|
|
NV Energy, Inc.
|
|
Xcel Energy Inc.
|
DPL, Inc.
|
|
Pepco Holdings, Inc.
|
|
|
Edison International
|
|
PG&E Corporation
|
|
|
|
The scale below determined the percentage of each quarters
dividend paid in the last year of the performance-measurement
period to be paid on each option held at December 31, 2009,
based on performance during the
2006-2009
performance-measurement period. Payout for performance between
points was interpolated on a straight-line basis.
|
|
|
|
|
|
|
Payout (% of Each
|
Performance vs. Peer Group
|
|
Quarterly Dividend Paid)
|
|
|
90th percentile or higher
|
|
|
100
|
|
|
50th percentile (Target)
|
|
|
50
|
|
|
10th percentile or lower
|
|
|
0
|
|
|
For tax purposes, the Compensation Committee approved a payout
for the named executive officers of up to 0.6% of the
Companys average net income over the
performance-measurement period and used negative discretion to
arrive at a payout commensurate with the scale shown.
The Companys total shareholder return performance, as
measured at the end of each quarter of the final year of the
four-year performance-measurement period ending with 2009, was
the 83rd,
83rd,
53rd, and
38th
percentile, respectively, resulting in a total payout of 64% of
the full years Common Stock dividend, or $1.10. This
amount was multiplied by each named executive officers
outstanding stock options at December 31, 2009 to calculate
the payout under the program. The amount paid is included in the
Non-Equity Incentive Plan Compensation column in the Summary
Compensation Table.
2012
Opportunity
The Compensation Committee selected two peer groups for the
2009-2012
performance-measurement period (which will be used to determine
the 2012 payout amount). The results of the two peer groups will
be averaged to determine the payment level. One peer group
selected is a published index, the Philadelphia Utility Index.
The other peer group (custom peer group) is a group of companies
that the Company believes are similar to the Company in terms of
business models, including a mix of regulated and non-regulated
revenues.
42
The companies in the Philadelphia Utility Index are listed below.
|
|
|
|
Ameren Corporation
|
|
Exelon Corporation
|
American Electric Power Company, Inc.
|
|
FirstEnergy Corp.
|
CenterPoint Energy, Inc.
|
|
FPL Group, Inc.
|
Consolidated Edison, Inc.
|
|
Northeast Utilities
|
Constellation Energy Group, Inc.
|
|
PG&E Corporation
|
Dominion Resources Inc.
|
|
Progress Energy, Inc.
|
DTE Energy Company
|
|
Public Service Enterprise Group Inc.
|
Duke Energy Corporation
|
|
The AES Corporation
|
Edison International
|
|
Xcel Energy Inc.
|
Entergy Corporation
|
|
|
|
The companies in the custom peer group are listed below.
|
|
|
|
American Electric Power Company, Inc.
|
|
PG&E Corporation
|
Consolidated Edison, Inc.
|
|
Progress Energy, Inc.
|
Duke Energy Corporation
|
|
Wisconsin Energy Corporation
|
Northeast Utilities
|
|
Xcel Energy Inc.
|
NSTAR
|
|
|
|
The scale below will determine the percentage of each
quarters dividend paid in the last year of the
performance-measurement period to be paid on each option held at
December 31, 2012, based on the
2009-2012
performance-measurement period. Payout for performance between
points will be interpolated on a straight-line basis.
|
|
|
|
|
|
|
Payout (% of Each
|
Performance vs. Peer Groups
|
|
Quarterly Dividend Paid)
|
|
|
90th percentile or higher
|
|
|
100
|
|
|
50th percentile (Target)
|
|
|
50
|
|
|
10th percentile or lower
|
|
|
0
|
|
|
See the Grants of Plan-Based Awards table and the accompanying
information for more information about threshold, target, and
maximum payout opportunities for the
2009-2012
Performance Dividend Program.
Timing of
Performance-Based Compensation
As discussed above, EPS and business unit financial performance
goals for the 2009 annual Performance Pay Program were
established at the February 2009 Compensation Committee meeting.
Annual stock option grants also were made at that meeting. The
establishment of performance-based compensation goals and the
granting of stock options were not timed with the release of
material non-public information. This procedure was consistent
with prior practices. Stock option grants are made to new hires
or newly-eligible participants on preset, regular quarterly
dates that were approved by the Compensation Committee. The
exercise price of options granted to employees in 2009 was the
closing price of the Common Stock on the grant date or last
trading day before the grant date, if the grant date was not a
trading day.
Post-Employment
Compensation
As mentioned above, we provide certain post-employment
compensation to employees, including the named executive
officers.
Retirement Benefits
Generally, all full-time employees of the Company participate in
our funded Pension Plan after completing one year of service.
Normal retirement benefits become payable when participants both
attain age 65 and complete five years of participation. We
also provide unfunded benefits that count salary and annual
Performance Pay Program payouts that are
43
ineligible to be counted under the Pension Plan. (These plans
are the Supplemental Benefit Plan and the Supplemental Executive
Retirement Plan that are described in the chart on page 33
of this CD&A.) See the Pension Benefits table and the
information accompanying it for more information about
pension-related benefits.
The Company also provides the Deferred Compensation Plan which
is an unfunded plan that permits participants to defer income as
well as certain federal, state, and local taxes until a
specified date or their retirement, disability, death, or other
separation from service. Up to 50% of base salary and up to 100%
of performance-based compensation, except stock options, may be
deferred at the election of eligible employees. All of the named
executive officers are eligible to participate in the Deferred
Compensation Plan. See the Nonqualified Deferred Compensation
table and the information accompanying it for more information
about the Deferred Compensation Plan.
Change-in-Control Protections
The Compensation Committee initially approved the
change-in-control
protection program in 1998. The program provided some level of
severance benefits to all employees not part of a collective
bargaining unit, if the conditions of the program were met, as
described below. The Compensation Committee established this
program and the levels of severance amount in order to provide
certain compensatory protections to officers upon a change in
control and thereby allow them to negotiate aggressively with a
prospective purchaser. Providing such protections to our
employees in general would minimize disruption during a pending
or anticipated change in control. For all participants, payment
and vesting would occur only upon the occurrence of both an
actual change in control and loss of the individuals
position. In 2009, the Compensation Committee directed Towers
Perrin to review best practices for
change-in-control
programs and directed management to recommend any necessary
changes to the program to meet those best practices. The review
of the program was completed in 2009 and changes were made
effective in late 2009.
Change-in-control
protections, including severance pay and, in some situations,
vesting or payment of long-term performance-based awards, are
provided upon a change in control of the Company coupled with an
involuntary termination not for cause or a voluntary termination
for Good Reason. This means there is a double
trigger before severance benefits are paid; i.e.,
there must be both a change in control and a termination of
employment.
If the conditions described above are met, the named executive
officers are entitled to severance payments equal to three times
their base salary plus the annual Performance Pay Program amount
assuming target-level performance. Less than 15 officers of the
Company and its subsidiaries, including all of the named
executive officers, are entitled to this level of severance
payment. Most other officers of the Company and its subsidiaries
were entitled to severance payments equal to two times their
base salary plus the annual Performance Pay Program amount
assuming target-level performance. These amounts were consistent
with that provided by other companies of our size and in our
industry based on market data provided to the Compensation
Committee from its compensation consultant.
However, based on the review conducted in 2009, the Compensation
Committee made changes to our program. Notably, the following
changes were approved:
|
|
|
Elimination of the highest-level severance payment except for
the Companys Chief Executive Officer and Chief Operating
Officer. (Current participants, which include all of the named
executive officers, are not affected.)
|
|
|
Reduction of severance payment level from three times base
salary plus target Performance Pay Program opportunity to two
times that amount for all other executive officers of the
Company and reduction from two times to one times base salary
plus target Performance Pay Program opportunity for all other
officers of the Company and its subsidiaries. (Current executive
officers of the Company are not affected; effective immediately
for all other officers.)
|
|
|
Elimination of excise tax
gross-up for
all participants. (Current eligible participants, less than 15
officers, including all of the named executive officers, are not
affected.)
|
|
|
Elimination of program for all non-officers. (Effective
immediately.)
|
More information about post-employment compensation, including
severance arrangements under our
change-in-control
program, is included in the section entitled Potential Payments
upon Termination or Change in Control.
44
Executive
Stock Ownership Requirements
Effective January 1, 2006, the Compensation Committee
adopted Common Stock ownership requirements for officers of the
Company and its subsidiaries that are in a position of vice
president or above. All of the named executive officers are
covered by the requirements. The guidelines were implemented to
further align the interest of officers and stockholders by
promoting a long-term focus and long-term share ownership.
The types of ownership arrangements counted toward the
requirements are shares owned outright, those held in
Company-sponsored plans, and Common Stock accounts in the
Deferred Compensation Plan and the Supplemental Benefit Plan.
One-third of vested stock options may be counted, but, if so,
the ownership requirement is doubled. The ownership requirement
is reduced by one-half at age 60. Messrs Garrett and
Ratcliffe are over age 60.
The requirements are expressed as a multiple of base salary per
the table below.
|
|
|
|
|
|
|
Multiple of Salary without
|
|
Multiple of Salary Counting
|
Name
|
|
Counting Stock Options
|
|
1/3 of Vested Options
|
|
|
D. M. Ratcliffe
|
|
2.5 Times
|
|
5 Times
|
|
W. P. Bowers
|
|
3 Times
|
|
6 Times
|
|
T. A. Fanning
|
|
3 Times
|
|
6 Times
|
|
M. D. Garrett
|
|
1.5 Times
|
|
3 Times
|
|
C. D. McCrary
|
|
3 Times
|
|
6 Times
|
|
Current officers have until September 30, 2011 to meet the
applicable ownership requirement. Newly-elected officers have
five years from the date of their election to meet the
applicable ownership requirement.
Impact of
Accounting and Tax Treatments on Compensation
Section 162(m) of the Internal Revenue Code of 1986, as
amended (Code), limits the tax deductibility of each named
executive officers compensation that exceeds
$1 million per year unless the compensation is paid under a
performance-based plan as defined in the Code that has been
approved by stockholders. The Company has obtained stockholder
approval of the Omnibus Incentive Compensation Plan, under which
most of our performance-based compensation is paid. For tax
purposes, in order to ensure that annual performance-based
compensation and performance dividend payouts are fully
deductible under Section 162(m) of the Code, in February
2009, the Compensation Committee approved a formula that
represented a maximum annual performance-based compensation
amount payable and the maximum performance dividend amount
payable for the
2009-2012
performance-measurement period. For 2009 performance, the
Compensation Committee used (for annual performance-based
compensation), or will use (for performance dividends), negative
discretion from those amounts to determine the actual payouts
pursuant to the methodologies described above. Because our
policy is to maximize long-term stockholder value, as described
fully in this CD&A, tax deductibility is not the only
factor considered in setting compensation.
Policy on
Recovery of Awards
The 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 knowingly or grossly
negligently engaged in or failed to prevent the misconduct or is
subject to automatic forfeiture under the Sarbanes-Oxley Act of
2002, the executive officer will reimburse the Company the
amount of any payment in settlement of awards earned or accrued
during the
12-month
period following the first public issuance or filing that was
restated.
Company
Policy Regarding Hedging the Economic Risk of Stock
Ownership
The Companys policy is that insiders, including outside
directors, will not trade in Company options on the options
market and will not engage in short sales.
2010
Executive Compensation Program Changes
In 2009, the Compensation Committee made certain key changes to
the performance-based compensation program that affect all
employees of the Company, including the named executive
officers. Changes were made to both the annual and long-term
performance-based compensation programs.
45
Annual
Performance Pay Program
For annual performance-based compensation to be earned in 2010,
the Compensation Committee changed the goal weights and lowered
the maximum payout opportunity. Under the program in effect
since 2000, the 2009 goals were weighted 50% EPS and 50% ROE
with an adjustment of plus or minus 10% based on operational
goal performance. The maximum payout opportunity was 220% of the
target opportunity. (For more information, see the description
of the Performance Pay Program in the 2009 Performance-Based
Compensation section in this CD&A.) Under the program
effective in 2010, the goals are weighted one-third EPS,
one-third ROE, and one-third operational goals. The maximum
payout opportunity is reduced to 200% of target.
Long-Term
Performance-Based Compensation Program
The long-term performance-based compensation program that has
been in effect for many years has consisted of stock options
with associated performance dividends. Effective in 2010, stock
options were granted without associated performance dividends.
Performance dividends accounted for approximately 64% of the
total long-term performance-based compensation target value for
2009. In 2010, stock options represent 40% of the total value
and a new long-term performance-based compensation component was
granted: performance share units. Performance share units
represent 60% of the total long-term performance-based
compensation target value. A grant date fair value per unit is
determined. For the grant made in 2010, the value per unit was
$30.13. The total target value for performance share units is
divided by the value per unit to determine the number of
performance share units granted to each participant, including
the named executive officers. Each performance share unit
represents one share of Common Stock. At the end of the
three-year performance-measurement period, the number of units
will be adjusted up or down (zero to 200%) based on the
Companys total shareholder return relative to that of its
peers in the Philadelphia Utility Index and the custom peer
group. (The performance metric, performance scale, and the peer
groups used for the performance share units are the same as
those currently used for performance dividends.) The number of
performance share units earned will be paid in Common Stock. No
dividends or dividend equivalents will be paid or earned on the
performance share units.
The Compensation Committee also approved a transition period for
the Performance Dividend Program. There are three
performance-measurement periods that are still open:
2007-2010,
2008-2011,
and
2009-2012.
For these open periods, the performance at the end of each
period will be determined, as described above in this CD&A,
and the amount earned will be paid on the number of stock
options granted prior to 2010 that a participant holds at the
end of each period. Therefore, there will be three additional
payouts under the Performance Dividend Program. The number of
stock options used to calculate these payouts will be limited to
the number of stock options granted prior to 2010.
46
COMPENSATION COMMITTEE REPORT
The Compensation Committee met with management to review and
discuss the CD&A. Based on such review and discussion, the
Compensation Committee recommended to the Board of Directors
that the CD&A be included in the Companys Annual
Report on
Form 10-K
for the fiscal year ended December 31, 2009 and in this
Proxy Statement. The Board of Directors approved that
recommendation.
Members of the Compensation Committee:
J. Neal Purcell, Chair
Henry A. Clark III
H. William Habermeyer, Jr.
Donald M. James
The Summary Compensation Table shows the amount and type of
compensation received or earned in 2007, 2008, and 2009 by the
Chief Executive Officer, the Chief Financial Officer, and the
next three most highly-paid executive officers of the Company
who served in 2009. Collectively, these five officers are
referred to as the named executive officers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Equity
|
|
Nonqualified
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
|
|
Option
|
|
Plan
|
|
Compensation
|
|
All Other
|
|
|
Name and Principal
|
|
|
|
Salary
|
|
Bonus
|
|
Awards
|
|
Awards
|
|
Compensation
|
|
Earnings
|
|
Compensation
|
|
Total
|
Position
|
|
Year
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
(g)
|
|
(h)
|
|
(i)
|
|
(j)
|
|
David M. Ratcliffe
|
|
|
2009
|
|
|
|
1,172,908
|
|
|
|
|
|
|
|
|
|
|
|
1,790,228
|
|
|
|
5,019,745
|
|
|
|
2,745,370
|
|
|
|
76,223
|
|
|
|
10,804,474
|
|
Chairman, President,
|
|
|
2008
|
|
|
|
1,118,090
|
|
|
|
|
|
|
|
|
|
|
|
1,666,774
|
|
|
|
5,267,878
|
|
|
|
1,481,217
|
|
|
|
79,378
|
|
|
|
9,613,337
|
|
& CEO
|
|
|
2007
|
|
|
|
1,068,268
|
|
|
|
|
|
|
|
|
|
|
|
2,215,880
|
|
|
|
2,901,883
|
|
|
|
4,683,305
|
|
|
|
88,585
|
|
|
|
10,957,921
|
|
|
|
W. Paul Bowers
|
|
|
2009
|
|
|
|
614,870
|
|
|
|
|
|
|
|
|
|
|
|
491,085
|
|
|
|
967,334
|
|
|
|
931,232
|
|
|
|
44,410
|
|
|
|
3,048,931
|
|
Executive Vice
|
|
|
2008
|
|
|
|
557,476
|
|
|
|
56,510
|
|
|
|
|
|
|
|
201,808
|
|
|
|
1,001,174
|
|
|
|
185,472
|
|
|
|
770,837
|
|
|
|
2,773,277
|
|
President & CFO
|
|
|
2007
|
|
|
|
502,366
|
|
|
|
|
|
|
|
|
|
|
|
291,202
|
|
|
|
669,586
|
|
|
|
582,095
|
|
|
|
42,282
|
|
|
|
2,087,531
|
|
|
|
Thomas A. Fanning
|
|
|
2009
|
|
|
|
690,250
|
|
|
|
|
|
|
|
|
|
|
|
457,744
|
|
|
|
1,086,911
|
|
|
|
927,301
|
|
|
|
38,432
|
|
|
|
3,200,638
|
|
Executive Vice
|
|
|
2008
|
|
|
|
658,246
|
|
|
|
|
|
|
|
|
|
|
|
237,374
|
|
|
|
1,348,981
|
|
|
|
235,664
|
|
|
|
49,341
|
|
|
|
2,529,606
|
|
President & COO
|
|
|
2007
|
|
|
|
610,624
|
|
|
|
|
|
|
|
|
|
|
|
409,454
|
|
|
|
954,988
|
|
|
|
814,123
|
|
|
|
43,658
|
|
|
|
2,832,847
|
|
|
|
Michael D. Garrett
|
|
|
2009
|
|
|
|
722,149
|
|
|
|
|
|
|
|
|
|
|
|
466,229
|
|
|
|
847,998
|
|
|
|
1,701,049
|
|
|
|
47,587
|
|
|
|
3,785,012
|
|
President, Georgia
|
|
|
2008
|
|
|
|
679,641
|
|
|
|
|
|
|
|
|
|
|
|
248,343
|
|
|
|
1,283,734
|
|
|
|
666,453
|
|
|
|
48,411
|
|
|
|
2,926,582
|
|
Power Company
|
|
|
2007
|
|
|
|
613,731
|
|
|
|
|
|
|
|
|
|
|
|
413,075
|
|
|
|
828,844
|
|
|
|
2,259,654
|
|
|
|
47,440
|
|
|
|
4,162,744
|
|
|
|
Charles D. McCrary
|
|
|
2009
|
|
|
|
687,713
|
|
|
|
|
|
|
|
|
|
|
|
431,932
|
|
|
|
1,350,171
|
|
|
|
1,195,625
|
|
|
|
48,375
|
|
|
|
3,713,816
|
|
President, Alabama
|
|
|
2008
|
|
|
|
656,209
|
|
|
|
|
|
|
|
|
|
|
|
236,500
|
|
|
|
1,287,318
|
|
|
|
639,855
|
|
|
|
57,386
|
|
|
|
2,877,268
|
|
Power Company
|
|
|
2007
|
|
|
|
629,961
|
|
|
|
|
|
|
|
|
|
|
|
421,612
|
|
|
|
983,174
|
|
|
|
1,156,038
|
|
|
|
58,132
|
|
|
|
3,248,917
|
|
|
|
Column (e)
No equity-based compensation has been awarded to the named
executive officers, other than Option Awards which are reported
in column (f).
Column (f)
This column reports the aggregate grant date fair value of stock
option grants made during the applicable year, disregarding any
estimates of forfeitures related to service-based vesting
conditions. See Note 8 to the Financial Statements for a
discussion of the assumptions used in calculating these amounts.
47
Column (g)
The amounts in this column are the aggregate of the payouts
under the Performance Pay Program and the Performance Dividend
Program attributable to performance periods ended
December 31, 2009 that are discussed in the CD&A. The
amounts paid under each program to the named executive officers
are shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
Performance-Based
|
|
Performance
|
|
|
|
|
Compensation
|
|
Dividends
|
|
Total
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
D. M. Ratcliffe
|
|
|
892,279
|
|
|
|
4,127,466
|
|
|
|
5,019,745
|
|
|
W. P. Bowers
|
|
|
354,910
|
|
|
|
612,424
|
|
|
|
967,334
|
|
|
T. A. Fanning
|
|
|
393,826
|
|
|
|
693,085
|
|
|
|
1,086,911
|
|
|
M. D. Garrett
|
|
|
156,466
|
|
|
|
691,532
|
|
|
|
847,998
|
|
|
C. D. McCrary
|
|
|
581,117
|
|
|
|
769,054
|
|
|
|
1,350,171
|
|
|
Column (h)
This column reports the aggregate change in the actuarial
present value of each named executive officers accumulated
benefit under the Pension Plan and the supplemental pension
plans (collectively, Pension Benefits) during 2007, 2008, and
2009. The amount included for 2007 is the difference between the
actuarial present values of the Pension Benefits measured as of
September 30, 2006 and September 30, 2007. However,
the amount for 2008 is the difference between the actuarial
values of the Pension Benefits measured as of September 30,
2007 and December 31, 2008 15 months
rather than one year. September 30 was used as the measurement
date prior to 2008 because it was the date as of which the
Company measured its retirement benefit obligations for
accounting purposes. Starting in 2008, the Company changed its
measurement date to December 31. The amount for 2009 is the
difference between the actuarial values of the Pension Benefits
measured as of December 31, 2008 and December 31,
2009. The Pension Benefits as of each measurement date are based
on the named executive 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 any
subsidiary of the Company until their benefits commence at the
pension plans stated normal retirement date, generally
age 65. As a result, the amounts in column (h) related
to Pension Benefits represent the combined impact of several
factors growth in the named executive 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.
The present values of accumulated Pension Benefits as of
September 30, 2007 reflect new provisions that were made in
2007 regarding the form and timing of payments from the
supplemental pension plans. Those changes brought those plans
into compliance with Section 409A of the Code. The key
change was to the form of payment. Instead of providing monthly
payments for the lifetime of each named executive officer and
his spouse, these plans will pay the single sum value of those
benefits for an average lifetime in 10 annual installments. The
present value of accumulated benefits prior to
September 30, 2007 reflects supplemental pension benefits
being paid monthly for the lifetimes of the named executive
officers and their spouses. The 2007 change in pension value
reported in column (h) for each named executive officer is
greater than what it otherwise would have been due to the change
in the form of payment.
For more information about the Pension Benefits and the
assumptions used to calculate the actuarial present value of
accumulated benefits as of December 31, 2009, see the
information following the Pension Benefits table.
This column also reports any above-market earnings on deferred
compensation under the Deferred Compensation Plan (DCP);
however, there were no above-market earnings on deferred
compensation in 2009. For more information about the DCP, see
the Nonqualified Deferred Compensation table and the information
accompanying it.
48
The table below itemizes the amounts reported in this column.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Above-Market
|
|
|
|
|
|
|
Change in
|
|
Earnings on Deferred
|
|
|
|
|
|
|
Pension Value
|
|
Compensation
|
|
Total
|
Name
|
|
Year
|
|
($)
|
|
($)
|
|
($)
|
|
D. M. Ratcliffe
|
|
|
2009
|
|
|
|
2,745,370
|
|
|
|
0
|
|
|
|
2,745,370
|
|
|
|
|
2008
|
|
|
|
1,481,217
|
|
|
|
0
|
|
|
|
1,481,217
|
|
|
|
|
2007
|
|
|
|
4,646,301
|
|
|
|
37,004
|
|
|
|
4,683,305
|
|
|
W. P. Bowers
|
|
|
2009
|
|
|
|
931,232
|
|
|
|
0
|
|
|
|
931,232
|
|
|
|
|
2008
|
|
|
|
185,472
|
|
|
|
0
|
|
|
|
185,472
|
|
|
|
|
2007
|
|
|
|
577,633
|
|
|
|
4,462
|
|
|
|
582,095
|
|
|
T. A. Fanning
|
|
|
2009
|
|
|
|
927,301
|
|
|
|
0
|
|
|
|
927,301
|
|
|
|
|
2008
|
|
|
|
235,664
|
|
|
|
0
|
|
|
|
235,664
|
|
|
|
|
2007
|
|
|
|
809,570
|
|
|
|
4,553
|
|
|
|
814,123
|
|
|
M. D. Garrett
|
|
|
2009
|
|
|
|
1,701,049
|
|
|
|
0
|
|
|
|
1,701,049
|
|
|
|
|
2008
|
|
|
|
666,453
|
|
|
|
0
|
|
|
|
666,453
|
|
|
|
|
2007
|
|
|
|
2,250,828
|
|
|
|
8,826
|
|
|
|
2,259,654
|
|
|
C. D. McCrary
|
|
|
2009
|
|
|
|
1,195,625
|
|
|
|
0
|
|
|
|
1,195,625
|
|
|
|
|
2008
|
|
|
|
639,855
|
|
|
|
0
|
|
|
|
639,855
|
|
|
|
|
2007
|
|
|
|
1,150,499
|
|
|
|
5,539
|
|
|
|
1,156,038
|
|
|
Column (i)
This column reports the following items: perquisites, Company
contributions in 2009 to the Southern Company Employee Savings
Plan (ESP), which is a tax-qualified defined contribution plan
intended to meet requirements of Section 401(k) of the
Code, and contributions in 2009 under the Southern Company
Supplemental Benefit Plan (Non-Pension Related) (SBP). The SBP
is described more fully in the information following the
Nonqualified Deferred Compensation table.
The amounts reported for 2009 are itemized below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
ESP
|
|
SBP
|
|
Total
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
D. M. Ratcliffe
|
|
|
17,114
|
|
|
|
11,786
|
|
|
|
47,323
|
|
|
|
76,223
|
|
|
W. P. Bowers
|
|
|
13,419
|
|
|
|
12,128
|
|
|
|
18,863
|
|
|
|
44,410
|
|
|
T. A. Fanning
|
|
|
4,143
|
|
|
|
11,581
|
|
|
|
22,708
|
|
|
|
38,432
|
|
|
M. D. Garrett
|
|
|
10,757
|
|
|
|
12,495
|
|
|
|
24,335
|
|
|
|
47,587
|
|
|
C. D. McCrary
|
|
|
15,236
|
|
|
|
10,561
|
|
|
|
22,578
|
|
|
|
48,375
|
|
|
Description of Perquisites
Personal Financial Planning is provided for most officers
of the Company, including all of the named executive officers.
The Company pays for the services of the financial planner on
behalf of the officers, up to a maximum amount of $9,780 per
year, after the initial year that the benefit is provided. The
Company also provides a five-year allowance of $6,000 for estate
planning and tax return preparation fees.
Home Security Monitoring is provided by or under the
direction of the Companys security personnel. The amount
of the benefit reported here represents the incremental cost of
the Company-provided monitoring or the actual amount paid to a
third-party provider, as applicable. For the Company-provided
monitoring, the incremental cost is the full cost of providing
security monitoring at Company-owned facilities and covered
employees residences divided by the number of security
systems monitored.
49
Personal Use of Company-Provided Club
Memberships. The Company provides club
memberships to certain officers, including all of the named
executive officers. The memberships are provided for business
use; however, personal use is permitted. The amount included
reflects the pro-rata portion of the membership fees paid by the
Company that are attributable to the named executive
officers personal use. Direct costs associated with any
personal use, such as meals, are paid for or reimbursed by the
employee and therefore are not included.
Personal Use of Corporate-Owned Aircraft. The
Company owns aircraft that are used to facilitate business
travel. All flights on these aircraft must have a business
purpose, except 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 family member to accompany an
employee on a flight. However, because in such cases the
aircraft is being used for a business purpose, there is no
incremental cost associated with the family travel and no
amounts are included for such travel. Any additional expenses
incurred that are related to family travel are included.
Other Miscellaneous Perquisites. The amount
included reflects the full cost to the Company of providing the
following items: personal use of Company-provided tickets for
sporting and other entertainment events and gifts distributed to
and activities provided to attendees at Company-sponsored events.
50
This table provides information on stock option grants made and
goals established for future payouts under the Companys
performance-based compensation programs during 2009 by the
Compensation Committee. In this table, the annual Performance
Pay Program and the performance dividend amounts are referred to
as PPP and PDP, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option
|
|
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards:
|
|
Exercise
|
|
Fair
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
or Base
|
|
Value of
|
|
|
|
|
|
|
Estimated Possible Payouts Under
|
|
Securities
|
|
Price of
|
|
Stock and
|
|
|
|
|
|
|
Non-Equity Incentive Plan Awards
|
|
Underlying
|
|
Option
|
|
Option
|
|
|
Grant
|
|
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Options
|
|
Awards
|
|
Awards
|
Name
|
|
Date
|
|
|
|
($)
|
|
($)
|
|
($)
|
|
(#)
|
|
($/Sh)
|
|
($)
|
(a)
|
|
(b)
|
|
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
(g)
|
|
(h)
|
|
D. M. Ratcliffe
|
|
|
2/16/2009
|
|
|
|
PPP
|
|
|
|
10,165
|
|
|
|
1,129,467
|
|
|
|
2,484,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/16/2009
|
|
|
|
PDP
|
|
|
|
162,284
|
|
|
|
3,245,689
|
|
|
|
6,491,379
|
|
|
|
994,571
|
|
|
|
31.39
|
|
|
|
1,790,228
|
|
|
|
W. P. Bowers
|
|
|
2/16/2009
|
|
|
|
PPP
|
|
|
|
4,043
|
|
|
|
449,253
|
|
|
|
988,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/16/2009
|
|
|
|
PDP
|
|
|
|
24,079
|
|
|
|
481,588
|
|
|
|
963,176
|
|
|
|
272,825
|
|
|
|
31.39
|
|
|
|
491,085
|
|
|
|
T. A. Fanning
|
|
|
2/16/2009
|
|
|
|
PPP
|
|
|
|
4,487
|
|
|
|
498,514
|
|
|
|
1,096,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/16/2009
|
|
|
|
PDP
|
|
|
|
27,251
|
|
|
|
545,017
|
|
|
|
1,090,033
|
|
|
|
254,302
|
|
|
|
31.39
|
|
|
|
457,744
|
|
|
|
M. D. Garrett
|
|
|
2/16/2009
|
|
|
|
PPP
|
|
|
|
4,694
|
|
|
|
521,552
|
|
|
|
1,147,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/16/2009
|
|
|
|
PDP
|
|
|
|
27,190
|
|
|
|
543,795
|
|
|
|
1,087,590
|
|
|
|
259,016
|
|
|
|
31.39
|
|
|
|
466,229
|
|
|
|
C. D. McCrary
|
|
|
2/16/2009
|
|
|
|
PPP
|
|
|
|
4,470
|
|
|
|
496,681
|
|
|
|
1,092,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/16/2009
|
|
|
|
PDP
|
|
|
|
30,238
|
|
|
|
604,756
|
|
|
|
1,209,512
|
|
|
|
239,962
|
|
|
|
31.39
|
|
|
|
431,932
|
|
|
|
Columns (c),
(d), and (e)
The amounts reported as PPP reflect the amounts established by
the Compensation Committee in early 2009 to be paid for certain
levels of performance as of December 31, 2009 under the
Companys annual Performance Pay Program. The Compensation
Committee assigns each named executive officer a target
incentive opportunity, expressed as a percentage of base salary
as detailed in the CD&A. The amount paid to each named
executive officer under the annual program for actual 2009
performance is included in the Non-Equity Incentive Plan
Compensation column in the Summary Compensation Table and is
itemized in the notes following that table. More information
about the program, including the applicable performance criteria
established by the Compensation Committee, is provided in the
CD&A.
The Company also has a long-term performance-based compensation
program, the Performance Dividend Program, that pays
performance-based dividend equivalents based on the
Companys total shareholder return (TSR) compared with the
TSR of its peer companies over a four-year
performance-measurement period. The Compensation Committee
establishes the level of payout for prescribed levels of
performance over the performance-measurement period.
In February 2009, the Compensation Committee established the
Performance Dividend Program goal for the four-year
performance-measurement period beginning on January 1, 2009
and ending on December 31, 2012. The amount earned, if any,
in 2012 based on the performance for
2009-2012
will be paid following the end of the period. However, no amount
is earned and paid unless the Compensation Committee approves
the payment at the beginning of the final year of the
performance-measurement period. Also, nothing is earned unless
the Companys earnings are sufficient to fund a Common
Stock dividend at the same level or higher than in the prior
year.
The Performance Dividend Program pays to all option holders a
percentage of the Common Stock dividend paid to stockholders in
the last year of the performance-measurement period. It can
range from approximately 2.5% for performance above the
10th percentile compared with the performance of the peer
companies to 100% of the dividend if the Companys TSR is
at or above the 90th percentile. That amount is then paid
per option held at the end of the four-year
performance-measurement period. The amount, if any, ultimately
paid to the option holders, including the named executive
officers, at the end of the last year of the
2009-2012
performance-measurement period will be based on (1) the
Companys TSR compared to that of its peer companies as of
December 31, 2012, (2) the actual dividend, if any,
paid in 2012 to our stockholders, and (3) the number of
options granted prior to 2010 held by the option holders on
December 31, 2012.
51
The number of options held on December 31, 2012 will be
affected by the number of options, if any, exercised by the
named executive officers prior to December 31, 2012. None
of these components necessary to calculate the range of payout
under the Performance Dividend Program for the
2009-2012
performance-measurement period is known at the time the goal is
established.
The amounts reported as PDP in columns (c), (d), and
(e) were calculated based on the number of options held by
the named executive officers on December 31, 2009, as
reported in columns (b) and (c) of the Outstanding
Equity Awards at 2009 Fiscal Year-End table, and the Common
Stock dividend of $1.73 per share paid to stockholders in 2009.
These factors are itemized below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options
|
|
Performance Dividend
|
|
Performance Dividend
|
|
Performance Dividend
|
|
|
Held as of
|
|
Per Option
|
|
Per Option
|
|
Per Option Paid at
|
|
|
December 31,
|
|
Paid at Threshold
|
|
Paid at Target
|
|
Maximum
|
|
|
2009
|
|
Performance
|
|
Performance
|
|
Performance
|
Name
|
|
(#)
|
|
($)
|
|
($)
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
3,752,242
|
|
|
|
0.04325
|
|
|
|
0.86500
|
|
|
|
1.7300
|
|
|
W. P. Bowers
|
|
|
556,749
|
|
|
|
0.04325
|
|
|
|
0.86500
|
|
|
|
1.7300
|
|
|
T. A. Fanning
|
|
|
630,077
|
|
|
|
0.04325
|
|
|
|
0.86500
|
|
|
|
1.7300
|
|
|
M. D. Garrett
|
|
|
628,665
|
|
|
|
0.04325
|
|
|
|
0.86500
|
|
|
|
1.7300
|
|
|
C. D. McCrary
|
|
|
699,140
|
|
|
|
0.04325
|
|
|
|
0.86500
|
|
|
|
1.7300
|
|
|
More information about the Performance Dividend Program is
provided in the CD&A.
Columns
(f) and (g)
The stock options vest at the rate of one-third per year on the
anniversary date of the grant. Also, grants fully vest upon
termination as a result of death, total disability, or
retirement and expire five years after retirement, three years
after death or total disability, or their normal expiration date
if earlier. Please see Potential Payments upon Termination or
Change in Control for more information about the treatment of
stock options under different termination and
change-in-control
events.
The Compensation Committee granted these stock options to the
named executive officers at its regularly-scheduled meeting on
February 16, 2009. Under the terms of the Omnibus Incentive
Compensation Plan, the exercise price was set at the closing
price ($31.39 per share) on the last trading day prior to the
grant date, which was February 13, 2009.
Column (h)
The value of stock options granted in 2009 was derived using the
Black-Scholes stock option pricing model. The assumptions used
in calculating these amounts are discussed in Note 8 to the
Financial Statements.
52
This table provides information pertaining to all outstanding
stock options held by the named executive officers as of
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Awards
|
|
Stock Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
Awards:
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
Market or
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
Plan
|
|
Payout Value
|
|
|
|
|
|
|
Plan
|
|
|
|
|
|
|
|
Market
|
|
Awards:
|
|
of Unearned
|
|
|
|
|
|
|
Awards:
|
|
|
|
|
|
Number of
|
|
Value
|
|
Number of
|
|
Shares,
|
|
|
Number of
|
|
Number of
|
|
Number of
|
|
|
|
|
|
Shares or
|
|
of Shares
|
|
Unearned
|
|
Units
|
|
|
Securities
|
|
Securities
|
|
Securities
|
|
|
|
|
|
Units of
|
|
or Units
|
|
Shares,
|
|
or Other
|
|
|
Underlying
|
|
Underlying
|
|
Underlying
|
|
|
|
|
|
Stock
|
|
of Stock
|
|
Units or
|
|
Rights
|
|
|
Unexercised
|
|
Unexercised
|
|
Unexercised
|
|
Option
|
|
|
|
That
|
|
That Have
|
|
Other Rights
|
|
That Have
|
|
|
Options
|
|
Options
|
|
Unearned
|
|
Exercise
|
|
Option
|
|
Have Not
|
|
Not
|
|
That Have
|
|
Not
|
|
|
Exercisable
|
|
Unexercisable
|
|
Options
|
|
Price
|
|
Expiration
|
|
Vested
|
|
Vested
|
|
Not Vested
|
|
Vested
|
Name
|
|
(#)
|
|
(#)
|
|
(#)
|
|
($)
|
|
Date
|
|
(#)
|
|
($)
|
|
(#)
|
|
($)
|
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
(g)
|
|
(h)
|
|
(i)
|
|
(j)
|
|
|
D. M. Ratcliffe
|
|
|
92,521
|
|
|
|
0
|
|
|
|
|
25.26
|
|
02/15/2012
|
|
|
|
|
|
|
|
|
|
|
|
82,265
|
|
|
|
0
|
|
|
|
|
29.50
|
|
02/13/2014
|
|
|
|
|
|
|
|
|
|
|
|
273,031
|
|
|
|
0
|
|
|
|
|
29.315
|
|
08/02/2014
|
|
|
|
|
|
|
|
|
|
|
|
550,000
|
|
|
|
0
|
|
|
|
|
32.70
|
|
02/18/2015
|
|
|
|
|
|
|
|
|
|
|
|
518,739
|
|
|
|
0
|
|
|
|
|
33.81
|
|
02/20/2016
|
|
|
|
|
|
|
|
|
|
|
|
358,557
|
|
|
|
179,278
|
|
|
|
|
36.42
|
|
02/19/2017
|
|
|
|
|
|
|
|
|
|
|
|
234,427
|
|
|
|
468,853
|
|
|
|
|
35.78
|
|
02/18/2018
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
994,571
|
|
|
|
|
31.39
|
|
02/16/2019
|
|
|
|
|
|
|
|
|
|
|
W. P. Bowers
|
|
|
60,576
|
|
|
|
0
|
|
|
|
|
32.70
|
|
02/18/2015
|
|
|
|
|
|
|
|
|
|
|
|
67,517
|
|
|
|
0
|
|
|
|
|
33.81
|
|
02/20/2016
|
|
|
|
|
|
|
|
|
|
|
|
47,120
|
|
|
|
23,560
|
|
|
|
|
36.42
|
|
02/19/2017
|
|
|
|
|
|
|
|
|
|
|
|
28,384
|
|
|
|
56,767
|
|
|
|
|
35.78
|
|
02/18/2018
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
272,825
|
|
|
|
|
31.39
|
|
02/16/2019
|
|
|
|
|
|
|
|
|
|
|
T. A. Fanning
|
|
|
80,843
|
|
|
|
0
|
|
|
|
|
32.70
|
|
02/18/2015
|
|
|
|
|
|
|
|
|
|
|
|
95,392
|
|
|
|
0
|
|
|
|
|
33.81
|
|
02/20/2016
|
|
|
|
|
|
|
|
|
|
|
|
66,255
|
|
|
|
33,127
|
|
|
|
|
36.42
|
|
02/19/2017
|
|
|
|
|
|
|
|
|
|
|
|
33,386
|
|
|
|
66,772
|
|
|
|
|
35.78
|
|
02/18/2018
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
254,302
|
|
|
|
|
31.39
|
|
02/16/2019
|
|
|
|
|
|
|
|
|
|
|
M. D. Garrett
|
|
|
17,806
|
|
|
|
0
|
|
|
|
|
29.50
|
|
02/13/2014
|
|
|
|
|
|
|
|
|
|
|
|
52,376
|
|
|
|
0
|
|
|
|
|
32.70
|
|
02/18/2015
|
|
|
|
|
|
|
|
|
|
|
|
94,420
|
|
|
|
0
|
|
|
|
|
33.81
|
|
02/20/2016
|
|
|
|
|
|
|
|
|
|
|
|
66,841
|
|
|
|
33,420
|
|
|
|
|
36.42
|
|
02/19/2017
|
|
|
|
|
|
|
|
|
|
|
|
34,929
|
|
|
|
69,857
|
|
|
|
|
35.78
|
|
02/18/2018
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
259,016
|
|
|
|
|
31.39
|
|
02/16/2019
|
|
|
|
|
|
|
|
|
|
|
C. D. McCrary
|
|
|
71,424
|
|
|
|
0
|
|
|
|
|
29.50
|
|
02/13/2014
|
|
|
|
|
|
|
|
|
|
|
|
86,454
|
|
|
|
0
|
|
|
|
|
32.70
|
|
02/18/2015
|
|
|
|
|
|
|
|
|
|
|
|
99,178
|
|
|
|
0
|
|
|
|
|
33.81
|
|
02/20/2016
|
|
|
|
|
|
|
|
|
|
|
|
68,222
|
|
|
|
34,111
|
|
|
|
|
36.42
|
|
02/19/2017
|
|
|
|
|
|
|
|
|
|
|
|
33,263
|
|
|
|
66,526
|
|
|
|
|
35.78
|
|
02/18/2018
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
239,962
|
|
|
|
|
31.39
|
|
02/16/2019
|
|
|
|
|
|
|
|
|
|
|
Stock options vest one-third per year on the anniversary of the
grant date. Options granted from 2002 through 2006, with
expiration dates from 2012 through 2016, were fully vested as of
December 31, 2009. The options granted in 2007, 2008, and
2009 become fully vested as shown below.
|
|
|
|
|
Year Option Granted
|
|
Expiration Date
|
|
Date Fully Vested
|
|
|
2007
|
|
February 19, 2017
|
|
February 19, 2010
|
|
2008
|
|
February 18, 2018
|
|
February 18, 2011
|
|
2009
|
|
February 16, 2019
|
|
February 16, 2012
|
|
53
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.
This table reports the number of shares acquired upon the
exercise of stock options during 2009 and the value realized
based on the difference in the market price over the exercise
price on the exercise date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Awards
|
|
Stock Awards
|
|
|
Number of Shares
|
|
|
|
Number of Shares
|
|
|
|
|
Acquired on
|
|
Value Realized on
|
|
Acquired on
|
|
Value Realized on
|
|
|
Exercise
|
|
Exercise
|
|
Vesting
|
|
Vesting
|
Name
|
|
(#)
|
|
($)
|
|
(#)
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
0
|
|
|
|
0
|
|
|
0
|
|
0
|
|
W. P. Bowers
|
|
|
0
|
|
|
|
0
|
|
|
0
|
|
0
|
|
T. A. Fanning
|
|
|
90,529
|
|
|
|
435,518
|
|
|
0
|
|
0
|
|
M. D. Garrett
|
|
|
0
|
|
|
|
0
|
|
|
0
|
|
0
|
|
C. D. McCrary
|
|
|
0
|
|
|
|
0
|
|
|
0
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
Present Value of
|
|
Payments
|
|
|
|
|
Years Credited
|
|
Accumulated
|
|
During
|
|
|
|
|
Service
|
|
Benefit
|
|
Last Fiscal Year
|
Name
|
|
Plan Name
|
|
(#)
|
|
($)
|
|
($)
|
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
|
D. M. Ratcliffe
|
|
Pension Plan
|
|
|
37.83
|
|
|
|
1,222,310
|
|
|
|
|
|
Supplemental Benefit Plan (Pension-Related)
|
|
|
37.83
|
|
|
|
13,216,934
|
|
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
37.83
|
|
|
|
4,080,758
|
|
|
|
|
W. P. Bowers
|
|
Pension Plan
|
|
|
29.67
|
|
|
|
612,513
|
|
|
|
|
|
Supplemental Benefit Plan (Pension-Related)
|
|
|
29.67
|
|
|
|
2,079,445
|
|
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
29.67
|
|
|
|
698,539
|
|
|
|
|
T. A. Fanning
|
|
Pension Plan
|
|
|
28.00
|
|
|
|
569,414
|
|
|
|
|
|
Supplemental Benefit Plan (Pension-Related)
|
|
|
28.00
|
|
|
|
2,613,276
|
|
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
28.00
|
|
|
|
848,729
|
|
|
|
|
M. D. Garrett
|
|
Pension Plan
|
|
|
40.75
|
|
|
|
1,258,587
|
|
|
|
|
|
Supplemental Benefit Plan (Pension-Related)
|
|
|
40.75
|
|
|
|
6,068,232
|
|
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
40.75
|
|
|
|
1,971,338
|
|
|
|
|
C. D. McCrary
|
|
Pension Plan
|
|
|
35.00
|
|
|
|
968,854
|
|
|
|
|
|
Supplemental Benefit Plan (Pension-Related)
|
|
|
35.00
|
|
|
|
4,332,918
|
|
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
35.00
|
|
|
|
1,413,552
|
|
|
|
|
The named executive officers earn employer-paid pension benefits
from three integrated retirement plans. More information about
pension benefits is provided in the CD&A.
Pension
Plan
The Pension Plan is a tax-qualified, funded plan. It is the
Companys primary retirement plan. Generally, all full-time
employees participate in this plan after one year of service.
Normal retirement benefits become payable when participants
54
both attain age 65 and complete five years of
participation. The plan benefit equals the greater of amounts
computed using a 1.7% offset formula and a
1.25% formula as described below. Benefits are
limited to a statutory maximum.
The 1.7% offset formula amount equals 1.7% of final average pay
times years of participation less an offset related to Social
Security benefits. The offset equals a service ratio times 50%
of the anticipated Social Security benefits in excess of $4,200.
The service ratio adjusts the offset for the portion of a full
career that a participant has worked. The highest three rates of
pay out of a participants last 10 calendar years of
service are averaged to derive final average pay. The pay
considered for this formula is the base rate of pay reduced for
any voluntary deferrals. A statutory limit restricts the amount
considered each year. The limit for 2009 was $245,000.
The 1.25% formula amount equals 1.25% of final average pay times
years of participation. For this formula, the final average pay
computation is the same as above, but annual cash incentives
paid during each year are added to the base rates of pay.
Early retirement benefits become payable once plan participants
have during employment both attained age 50 and completed
10 years of participation. Participants who retire early
from active service receive benefits equal to the amounts
computed using the same formulas employed at normal retirement.
However, a 0.3% reduction applies for each month (3.6% for each
year) prior to normal retirement that participants elect to have
their benefit payments commence. For example, 64% of the formula
benefits are payable starting at age 55. All of the named
executive officers are eligible to retire immediately.
The Pension 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. All the named executive officers are vested in
their Pension Plan benefits. Participants who terminate
employment after vesting can elect to have their pension
benefits commencing at age 50 if they participated in the
Pension Plan for 10 years. If such an election is made, the
early retirement reductions that apply are actuarially
determined factors and are larger than 0.3% per month.
If a participant dies while actively employed, benefits will be
paid to a surviving spouse. A 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 the extra service crediting, the normal plan
provisions apply to disabled participants.
The
Southern Company Supplemental Benefit Plan (Pension-Related)
(SBP-P)
The SBP-P is an unfunded retirement plan that is not
tax-qualified. This plan provides to high-paid employees any
benefits that the Pension Plan cannot pay due to statutory
pay/benefit limits and voluntary pay deferrals. The SBP-Ps
vesting, early retirement, and disability provisions mirror
those of the Pension Plan.
The amounts paid by the SBP-P are based on the additional
monthly benefit that the Pension Plan would pay if the statutory
limits and pay deferrals were ignored. When an SBP-P participant
separates from service, vested monthly benefits provided by the
benefit formulas are converted into a single sum value. It
equals the present value of what would have been paid monthly
for an actuarially determined average post-retirement lifetime.
The discount rate used in the calculation is based on the
30-year
Treasury yields for the September preceding the calendar year of
separation, but not more than 6%. Vested participants
terminating prior to becoming eligible to retire will be paid
their single sum value as of September 1 following the calendar
year of separation. If the terminating participant is
retirement-eligible, the single sum value will be paid in 10
annual installments starting shortly after separation. The
unpaid balance of a retirees single sum will be credited
with interest
55
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 survivor as if
the participant had survived to age 50.
The
Southern Company Supplemental Executive Retirement Plan
(SERP)
The SERP also is an unfunded retirement plan that is not
tax-qualified. This plan provides to highly-paid employees
additional benefits that the Pension Plan and the SBP-P would
pay if the 1.7% offset formula calculations reflected a portion
of annual cash incentives. To derive the SERP benefits, a final
average pay is determined reflecting participants base
rates of pay and their incentives to the extent they exceed 15%
of those base rates (ignoring statutory limits and pay
deferrals). This final average pay is used in the 1.7% offset
formula to derive a gross benefit. The Pension Plan and the
SBP-P benefits are subtracted from the gross benefit to
calculate the SERP benefit. The SERPs early retirement,
survivor benefit, and disability 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 eligible to retire. More information about vesting and
payment of SERP benefits following a change in control is
included in the section entitled Potential Payments upon
Termination or Change in Control.
The following assumptions were used in the present value
calculations:
|
|
|
Discount rate 5.95% Pension Plan and 5.60%
supplemental plans as of December 31, 2009
|
|
Retirement date Normal retirement age (65 for all
named executive officers)
|
|
Mortality after normal retirement RP2000 Combined
Healthy with generational projections
|
|
Mortality, withdrawal, disability, and retirement rates prior to
normal retirement None
|
|
Form of payment for Pension Benefits
|
|
|
|
|
|
Male retirees: 25% single life annuity; 25% level income
annuity; 25% joint and 50% survivor annuity; and 25% joint and
100% survivor annuity
|
|
|
Female retirees: 40% single life annuity; 40% level income
annuity; 10% joint and 50% survivor annuity; and 10% joint and
100% survivor annuity
|
|
|
|
Spouse ages Wives two years younger than their
husbands
|
|
Annual performance-based compensation earned but unpaid as of
the measurement date 130% of target opportunity
percentages times base rate of pay for year incentive is earned
|
|
Installment determination 4.25% discount rate for
single sum calculation and 5.25% prime rate during installment
payment period
|
For all of the named executive officers, the number of years of
credited service is one year less than the number of years of
employment.
NONQUALIFIED DEFERRED COMPENSATION AS OF 2009 FISCAL
YEAR-END
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executive
|
|
Registrant
|
|
|
|
Aggregate
|
|
|
|
|
Contributions
|
|
Contributions
|
|
Aggregate Earnings
|
|
Withdrawals/
|
|
Aggregate Balance
|
|
|
in Last FY
|
|
in Last FY
|
|
in Last FY
|
|
Distributions
|
|
at Last FYE
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
D. M. Ratcliffe
|
|
|
0
|
|
|
|
47,323
|
|
|
|
(85,521
|
)
|
|
|
0
|
|
|
|
9,450,240
|
|
|
W. P. Bowers
|
|
|
369,101
|
|
|
|
18,863
|
|
|
|
52,656
|
|
|
|
0
|
|
|
|
1,481,038
|
|
|
T. A. Fanning
|
|
|
134,898
|
|
|
|
22,708
|
|
|
|
4,130
|
|
|
|
0
|
|
|
|
1,234,022
|
|
|
M. D. Garrett
|
|
|
0
|
|
|
|
24,335
|
|
|
|
25,222
|
|
|
|
0
|
|
|
|
1,355,526
|
|
|
C. D. McCrary
|
|
|
0
|
|
|
|
22,578
|
|
|
|
1,536
|
|
|
|
0
|
|
|
|
1,160,512
|
|
|
56
The Company provides the DCP which is designed to permit
participants to defer income as well as certain federal, state,
and local taxes until a specified date or their retirement,
disability, or other separation from service. Up to 50% of base
salary and up to 100% of performance-based compensation, except
stock options, may be deferred, at the election of eligible
employees. All of the named executive officers are eligible to
participate in the DCP.
Participants have two options for the deemed investments of the
amounts deferred the Stock Equivalent Account and
the Prime Equivalent Account. Under the terms of the DCP,
participants are permitted to transfer between investments at
any time.
The amounts deferred in the Stock Equivalent Account are treated
as if invested at an equivalent rate of return to that of an
actual investment in Common Stock, including the crediting of
dividend equivalents as such are paid by the Company from time
to time. It provides participants with an equivalent opportunity
for the capital appreciation (or loss) and income as that of a
Company stockholder. During 2009, the rate of return in the
Stock Equivalent Account was (4.83%), which was the
Companys TSR for 2009.
Alternatively, participants may elect to have their deferred
compensation deemed invested in the Prime Equivalent Account
which is treated as if invested at a prime interest rate
compounded monthly, as published in The Wall Street Journal
as the base rate on corporate loans posted as of the last
business day of each month by at least 75% of the United
States largest banks. The interest rate earned on amounts
deferred during 2009 in the Prime Equivalent Account was 3.25%.
Column (b)
This column reports the actual amounts of compensation deferred
under the DCP by each named executive officer in 2009. The
amount of salary deferred by the named executive officers, if
any, is included in the Salary column in the Summary
Compensation Table. The amount of performance-based compensation
deferred in 2009 was the amount paid for performance under the
annual Performance Pay Program and the Performance Dividend
Program that were earned as of December 31, 2008 but not
payable until the first quarter of 2009. This amount is not
reflected in the Summary Compensation Table because that table
reports performance-based compensation that was earned in 2009,
but not payable until early 2010. These deferred amounts may be
distributed in a lump sum or in up to 10 annual installments at
termination of employment or in a lump sum at a specified date,
at the election of the participant.
Column (c)
This column reflects contributions under the SBP. Under the
Code, employer matching contributions are prohibited under the
ESP on employee contributions above stated limits in the ESP,
and, if applicable, above legal limits set forth in the Code.
The SBP is a nonqualified deferred compensation plan under which
contributions are made that are prohibited from being made in
the ESP. The contributions are treated as if invested in Common
Stock and are payable in cash upon termination of employment in
a lump sum or in up to 20 annual installments, at the election
of the participant. The amounts reported in this column also
were reported in the All Other Compensation column in the
Summary Compensation Table.
Column (d)
This column reports earnings or losses both on compensation the
named executive officers elected to defer and on employer
contributions under the SBP. See the notes to column (h) of
the Summary Compensation Table for a discussion of amounts of
nonqualified deferred compensation earnings included in the
Summary Compensation Table.
Column (e)
There were no aggregate withdrawals or distributions.
57
Column (f)
This column includes amounts that were deferred under the DCP
and contributions under the SBP in prior years and reported in
prior years Proxy Statements. The chart below shows the
amounts reported in prior years Proxy Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employer Contributions
|
|
|
|
|
Amounts Deferred under
|
|
under the SBP
|
|
|
|
|
the DCP Prior to 2009
|
|
Prior to 2009 and
|
|
|
|
|
and Reported in Prior
|
|
Reported in Prior Years
|
|
|
|
|
Years Proxy Statements
|
|
Proxy Statements
|
|
Total
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
5,381,881
|
|
|
|
292,081
|
|
|
|
5,673,962
|
|
|
W. P. Bowers
|
|
|
287,965
|
|
|
|
28,900
|
|
|
|
316,865
|
|
|
T. A. Fanning
|
|
|
838,422
|
|
|
|
103,938
|
|
|
|
942,360
|
|
|
M. D. Garrett
|
|
|
0
|
|
|
|
92,928
|
|
|
|
92,928
|
|
|
C. D. McCrary
|
|
|
489,924
|
|
|
|
172,851
|
|
|
|
662,775
|
|
|
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
This section describes and estimates payments that could be made
to the named executive officers under different termination and
change-in-control
events. The estimated payments would be made under the terms of
the Companys compensation and benefit programs or the
change-in-control
severance agreements with each of the named executive officers.
The amount of potential payments is calculated as if the
triggering events occurred as of December 31, 2009 and
assumes that the price of Common Stock is the closing market
price on December 31, 2009.
Description
of Termination and
Change-in-Control
Events
The following charts list different types of termination and
change-in-control
events that can affect the treatment of payments under the
Companys compensation and benefit programs. These events
also affect payments to the named executive officers under their
change-in-control
severance agreements. No payments are made under the severance
agreements unless within two years of the change in control, the
named executive officer is involuntarily terminated or
voluntarily terminates for Good Reason. (See the description of
Good Reason below.)
Traditional
Termination Events
|
|
|
Retirement or Retirement-Eligible Termination of a
named executive officer who is at least 50 years old and
has at least 10 years of credited service.
|
|
|
Resignation Voluntary termination of a named
executive officer who is not retirement-eligible.
|
|
|
Lay Off Involuntary termination not for cause of a
named executive officer who is not retirement-eligible.
|
|
|
Involuntary Termination Involuntary termination of a
named executive officer for cause. Cause includes individual
performance below minimum performance standards and misconduct,
such as violation of the 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 subsidiary level:
|
|
|
Southern Change in Control I Acquisition by another
entity of 20% or more of Common Stock or, following a merger
with another entity, the Companys stockholders own 65% or
less of the entity surviving the merger.
|
|
|
Southern Change in Control II Acquisition by another
entity of 35% or more of Common Stock or, following a merger
with another entity, the Companys stockholders own less
than 50% of the entity surviving the merger.
|
58
|
|
|
Southern Termination A merger or other event and the
Company is not the surviving company or Common Stock is no
longer publicly traded.
|
|
|
Subsidiary Change in Control Acquisition by another
entity, other than another subsidiary of the Company, of 50% or
more of the stock of a subsidiary of the Company, a merger with
another entity and the subsidiary is not the surviving company,
or the sale of substantially all the assets of the subsidiary.
|
At the
employee level:
|
|
|
Involuntary
Change-in-Control
Termination or Voluntary
Change-in-Control
Termination for Good Reason Employment is terminated
within two years of a change in control, other than for cause,
or the employee voluntarily terminates for Good Reason. Good
Reason for voluntary termination within two years of a change in
control generally is satisfied when there is a material
reduction in salary, performance-based compensation opportunity
or benefits, relocation of over 50 miles, or a diminution
in duties and responsibilities.
|
The following chart describes the treatment of different
compensation and benefit elements in connection with the
Traditional Termination Events described above. All of the named
executive officers are eligible to retire under the terms of our
pension benefits plans and therefore any termination of
employment also would be a retirement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lay Off
|
|
|
|
|
|
|
|
|
Retirement/
|
|
(Involuntary
|
|
|
|
|
|
Involuntary
|
|
|
Retirement-
|
|
Termination
|
|
|
|
Death or
|
|
Termination
|
Program
|
|
Eligible
|
|
Not For Cause)
|
|
Resignation
|
|
Disability
|
|
(For Cause)
|
|
|
Pension Benefits Plans
|
|
Benefits payable as described in the notes following the Pension
Benefits table.
|
|
Same as Retirement.
|
|
Same as Retirement.
|
|
Same as Retirement.
|
|
Same as Retirement.
|
|
Annual Performance Pay Program
|
|
Pro-rated if terminate before 12/31.
|
|
Same as Retirement.
|
|
Forfeit.
|
|
Same as Retirement.
|
|
Forfeit.
|
|
Performance Dividend Program
|
|
Paid year of retirement plus two additional years.
|
|
Forfeit.
|
|
Forfeit.
|
|
Payable until options expire or exercised.
|
|
Forfeit.
|
|
Stock Options
|
|
Vest; expire earlier of original expiration date or five years.
|
|
Vested options expire in 90 days; unvested are forfeited.
|
|
Same as Lay Off.
|
|
Vest; expire earlier of original expiration or three years.
|
|
Forfeit.
|
|
Financial Planning Perquisite
|
|
Continues for one year.
|
|
Terminates.
|
|
Terminates.
|
|
Same as Retirement.
|
|
Terminates.
|
|
Deferred Compensation Plan (DCP)
|
|
Payable per prior elections (lump sum or up to 10 annual
installments).
|
|
Same as Retirement.
|
|
Same as Retirement.
|
|
Payable to beneficiary or disabled participant per prior
elections; amounts deferred prior to 2005 can be paid as a lump
sum per benefits administration committees discretion.
|
|
Same as Retirement.
|
|
Supplemental Benefit Plan (SBP) non-pension
related
|
|
Payable per prior elections (lump sum or up to 20 annual
installments).
|
|
Same as Retirement.
|
|
Same as Retirement.
|
|
Same as the DCP.
|
|
Same as Retirement.
|
|
59
The chart below describes the treatment of payments under
compensation and benefit programs under different
change-in-control
events. The Pension Plan, the DCP, and the SBP are not affected
by
change-in-control
events.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Involuntary
|
|
|
|
|
|
|
|
|
Change-in-
|
|
|
|
|
|
|
|
|
Control-Related
|
|
|
|
|
|
|
|
|
Termination or
|
|
|
|
|
|
|
|
|
Voluntary
|
|
|
|
|
|
|
Southern
|
|
Change-in-
|
|
|
|
|
|
|
Termination or
|
|
Control-Related
|
|
|
Southern Change
|
|
Southern Change
|
|
Subsidiary Change
|
|
Termination
|
Program
|
|
in Control I
|
|
in Control II
|
|
in Control
|
|
for Good Reason
|
|
|
Nonqualified Pension Benefits
|
|
All SERP-related benefits vest if participant vested in
tax-qualified pension benefits; otherwise, no impact.
SBP-pension-related benefits vest for all participants and
single sum value of benefits earned to change-in-control date
paid following termination or retirement.
|
|
Benefits vest for all participants and single sum value of
benefits earned to the change-in-control date paid following
termination or retirement.
|
|
Same as Southern Change in Control II.
|
|
Based on type of change-in-control event.
|
|
Annual Performance Pay Program
|
|
If program is not terminated, then is paid at greater of target
or actual performance. If program is terminated within two years
of change in control; pro-rated at target performance level.
|
|
Same as Southern Change in Control I.
|
|
Pro-rated at target performance level.
|
|
If not otherwise eligible for payment and if the program still
in effect, pro-rated at target performance level.
|
|
Performance Dividend Program
|
|
If program is not terminated, then is paid at greater of target
or actual performance. If program terminated within two years of
change in control; pro-rated at greater of target or actual
performance level.
|
|
Same as Southern Change in Control I.
|
|
Pro-rated at greater of actual or target performance level.
|
|
If not otherwise eligible for payment and if the program still
in effect, greater of actual or target performance level for
year of severance only.
|
|
Stock Options
|
|
Not affected by change-in-control events.
|
|
Not affected by change-in-control events.
|
|
Vest and convert to surviving companys securities; if
cannot convert, pay spread in cash; if participant is an
employee of a subsidiary, stock options vest upon a Subsidiary
Change in Control.
|
|
Vest.
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Involuntary
|
|
|
|
|
|
|
|
|
Change-in-
|
|
|
|
|
|
|
|
|
Control-Related
|
|
|
|
|
|
|
|
|
Termination or
|
|
|
|
|
|
|
|
|
Voluntary
|
|
|
|
|
|
|
Southern
|
|
Change-in-
|
|
|
|
|
|
|
Termination or
|
|
Control-Related
|
|
|
Southern Change
|
|
Southern Change
|
|
Subsidiary Change
|
|
Termination
|
Program
|
|
in Control I
|
|
in Control II
|
|
in Control
|
|
for Good Reason
|
|
|
Severance Benefits
|
|
Not applicable.
|
|
Not applicable.
|
|
Not applicable.
|
|
Three times base salary plus target annual performance-based
program amount plus tax gross-up if severance amounts exceed
Code Section 280G excess parachute payment by 10% or
more.
|
|
Health Benefits
|
|
Not applicable.
|
|
Not applicable.
|
|
Not applicable.
|
|
Up to five years participation in group health plan plus payment
of three years premium amounts.
|
|
Outplacement Services
|
|
Not applicable.
|
|
Not applicable.
|
|
Not applicable.
|
|
Six months.
|
|
Potential Payments
This section describes and estimates payments that would become
payable to the named executive officers upon a termination or
change in control as of December 31, 2009.
Pension
Benefits
The amounts that would have become payable to the named
executive officers if the Traditional Termination Events
occurred as of December 31, 2009 under the Pension Plan,
the SBP-P, and the SERP are itemized in the chart below. The
amounts shown under the Retirement column are amounts that would
have become payable to the named executive officers since all
were retirement-eligible on December 31, 2009 and are the
monthly Pension Plan benefits and the first of 10 annual
installments from the SBP-P and the SERP. The amounts shown that
are payable to a spouse in the event of the death of the named
executive officer are the monthly amounts payable to a spouse
under the Pension Plan and the first of 10 annual installments
from the SBP-P and the SERP. The amounts in this chart are very
different from the pension values shown in the Summary
Compensation Table and the Pension Benefits table. Those tables
show the present values of all the benefit amounts anticipated
to be paid over the lifetimes of the named executive officers
and their spouses. Those plans are described in the notes
following the Pension Benefits table.
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resignation or
|
|
|
Death
|
|
|
|
|
|
|
|
|
Involuntary Retirement
|
|
|
(payments
|
|
|
|
|
|
Retirement
|
|
|
(monthly payments)
|
|
|
to a spouse)
|
|
Name
|
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
|
D. M. Ratcliffe
|
|
Pension Plan
|
|
|
10,059
|
|
|
|
All plans treated as
|
|
|
|
5,251
|
|
|
|
Supplemental Benefit Plan
|
|
|
1,577,122
|
|
|
|
retiring
|
|
|
|
1,577,122
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
486,940
|
|
|
|
|
|
|
|
486,940
|
|
|
W. P. Bowers
|
|
Pension Plan
|
|
|
5,235
|
|
|
|
All plans treated as
|
|
|
|
4,147
|
|
|
|
Supplemental Benefit Plan
|
|
|
298,809
|
|
|
|
retiring
|
|
|
|
298,809
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
100,378
|
|
|
|
|
|
|
|
100,378
|
|
|
T. A. Fanning
|
|
Pension Plan
|
|
|
4,859
|
|
|
|
All plans treated as
|
|
|
|
3,912
|
|
|
|
Supplemental Benefit Plan
|
|
|
376,239
|
|
|
|
retiring
|
|
|
|
376,239
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
122,193
|
|
|
|
|
|
|
|
122,193
|
|
|
M. D. Garrett
|
|
Pension Plan
|
|
|
10,482
|
|
|
|
All plans treated as
|
|
|
|
5,690
|
|
|
|
Supplemental Benefit Plan
|
|
|
748,194
|
|
|
|
retiring
|
|
|
|
748,194
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
243,060
|
|
|
|
|
|
|
|
243,060
|
|
|
C. D. McCrary
|
|
Pension Plan
|
|
|
8,253
|
|
|
|
All plans treated as
|
|
|
|
4,945
|
|
|
|
Supplemental Benefit Plan
|
|
|
569,145
|
|
|
|
retiring
|
|
|
|
569,145
|
|
|
|
Supplemental Executive Retirement Plan
|
|
|
185,675
|
|
|
|
|
|
|
|
185,675
|
|
|
As described in the
Change-in-Control
chart, the only change in the form of payment, acceleration, or
enhancement of the Pension Benefits is that the single sum value
of benefits earned up to the
change-in-control
date under the SBP-P and the SERP could be paid as a single
payment rather than in 10 annual installments. Also, the SERP
benefits vest for participants who are not retirement-eligible
upon a change in control. Estimates of the single sum payment
that would have been made to the named executive officers,
assuming termination as of December 31, 2009 following a
change-in-control
event, other than a Southern Change in Control I (which does not
impact how pension benefits are paid), are itemized below. These
amounts would be paid instead of the benefits shown in the
Traditional Termination Events chart above; they are not paid in
addition to those amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SBP-P
|
|
SERP
|
|
Total
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
15,771,216
|
|
|
|
4,869,398
|
|
|
|
20,640,615
|
|
|
W. P. Bowers
|
|
|
2,988,093
|
|
|
|
1,003,776
|
|
|
|
3,991,869
|
|
|
T. A. Fanning
|
|
|
3,762,394
|
|
|
|
1,221,935
|
|
|
|
4,984,328
|
|
|
M. D. Garrett
|
|
|
7,481,938
|
|
|
|
2,430,598
|
|
|
|
9,912,536
|
|
|
C. D. McCrary
|
|
|
5,691,453
|
|
|
|
1,856,754
|
|
|
|
7,548,208
|
|
|
The pension benefit amounts in the tables above were calculated
as of December 31, 2009 assuming payments would begin as
soon as possible under the terms of the plans. Accordingly,
appropriate early retirement reductions were applied. Any unpaid
annual performance-based compensation was assumed to be paid at
1.3 times the target level. Pension Plan benefits were
calculated assuming each named executive officer chose a single
life annuity form of payment, because that results in the
greatest monthly benefit. The single sum values of the SBP-P and
the SERP benefits were based on a 4.25% discount rate as
prescribed by the terms of these plans.
Annual
Performance Pay Program
The amount payable if a change in control had occurred on
December 31, 2009 is the greater of target or actual
performance. Because actual payouts for 2009 performance were
below the target level, except for Mr. McCrary, the amount
that would have been payable was the target level amount as
reported in the Grants of Plan-Based Awards table. The amount
for Mr. McCrary would have been the amount paid as reported
in the Summary Compensation Table.
62
Performance
Dividends
Because the assumed termination date is December 31, 2009,
there is no additional amount that would be payable other than
the amount reported in the Summary Compensation Table. As
described in the Traditional Termination Events chart, there is
some continuation of benefits under the Performance Dividend
Program for retirees.
Stock
Options
Stock options would be treated as described in the Termination
and
Change-in-Control
charts above. Under a Southern Termination, all stock options
vest. In addition, if there is an Involuntary
Change-in-Control
Termination or Voluntary
Change-in-Control
Termination for Good Reason, stock options vest. There is no
payment associated with stock options unless there is a Southern
Termination and the participants stock options cannot be
converted into surviving company stock options. In that event,
the excess of the exercise price and the closing price of the
Common Stock on December 31, 2009 would be paid in cash for
all stock options held by the named executive officers. The
chart below shows the number of stock options for which vesting
would be accelerated under a Southern Termination and the amount
that would be payable under a Southern Termination if there were
no conversion to the surviving companys stock options.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Payable in
|
|
|
|
|
Total Number of
|
|
Cash
|
|
|
Number of
|
|
Options Following
|
|
under a Southern
|
|
|
Options with
|
|
Accelerated Vesting
|
|
Termination without
|
|
|
Accelerated
|
|
under a Southern
|
|
Conversion of Stock
|
Name
|
|
Vesting (#)
|
|
Termination (#)
|
|
Options ($)
|
|
|
D. M. Ratcliffe
|
|
|
1,642,702
|
|
|
|
3,752,242
|
|
|
|
4,413,983
|
|
|
W. P. Bowers
|
|
|
353,152
|
|
|
|
556,749
|
|
|
|
564,109
|
|
|
T. A. Fanning
|
|
|
354,201
|
|
|
|
630,077
|
|
|
|
540,926
|
|
|
M. D. Garrett
|
|
|
362,293
|
|
|
|
628,665
|
|
|
|
600,393
|
|
|
C. D. McCrary
|
|
|
340,599
|
|
|
|
699,140
|
|
|
|
789,568
|
|
|
DCP and
SBP
The aggregate balances reported in the Nonqualified Deferred
Compensation table would be payable to the named executive
officers as described in the Traditional Termination and
Change-in-Control-Related
Events charts above. There is no enhancement or acceleration of
payments under these plans associated with termination or
change-in-control
events, other than the lump-sum payment opportunity described in
the above charts. The lump sums that would be payable are those
that are reported in the Nonqualified Deferred Compensation
table.
Health
Benefits
Because all of the named executive officers are
retirement-eligible and health care benefits are provided to
retirees, there is no incremental payment associated with the
termination or
change-in-control
events.
Financial
Planning Perquisite
All of the named executive officers are retirement-eligible;
therefore, an additional year of the financial planning
perquisite would be provided. That amount is set at a maximum of
$9,780 per year.
There are no other perquisites provided to the named executive
officers under any of the traditional termination or
change-in-control-related
events.
Severance
Benefits
The Company has entered into individual
Change-in-Control
Severance Agreements with each of the named executive officers.
In addition to the treatment of health benefits, the annual
Performance Pay Program, and the Performance Dividend Program
described above, the named executive officers are entitled to a
severance benefit, including outplacement services, if, within
two years of a change in control, they are involuntarily
terminated, not for cause, or they voluntarily terminate for
Good Reason. The severance benefits are not paid unless the
named executive officer releases the Company from any claims he
may have against the Company.
63
The estimated cost of providing the six months of outplacement
services is $6,000 per named executive officer. The severance
payment is three times the named executive officers base
salary and target payout under the annual Performance Pay
Program. If any portion of the severance payment is an
excess parachute payment as defined under
Section 280G of the Code, the Company will pay the named
executive officer an additional amount to cover the taxes that
would be due on the excess parachute payment a
tax
gross-up.
However, that additional amount will not be paid unless the
severance amount plus all other amounts that are considered
parachute payments under the Code exceed 110% of the severance
payment.
The table below estimates the severance payments that would be
made to the named executive officers if they were terminated as
of December 31, 2009 in connection with a change in
control. There is no estimated tax
gross-up
included for any of the named executive officers because their
respective estimated severance amounts payable are below the
amounts considered excess parachute payments under the Code.
|
|
|
|
|
|
|
Severance Amount
|
Name
|
|
($)
|
|
|
D. M. Ratcliffe
|
|
|
6,776,802
|
|
|
W. P. Bowers
|
|
|
3,144,771
|
|
|
T. A. Fanning
|
|
|
3,489,597
|
|
|
M. D. Garrett
|
|
|
3,650,862
|
|
|
C. D. McCrary
|
|
|
3,476,769
|
|
|
The Compensation Committee considers risk when establishing
compensation program goals and objectives. The Compensation
Committee reviewed and discussed an assessment of the
Companys compensation policies and practices and concluded
that excessive or inappropriate risk-taking is not encouraged,
for the following reasons:
|
|
|
As described in detail in the CD&A, the Companys
total compensation program is a well-balanced mix of fixed
(salary) and short- and long-term performance-based compensation
(Performance Pay Program, stock options, and performance
dividends) that reward based on financial and operational goals,
stock price performance, and total shareholder return.
|
|
The annual pay/performance analysis conducted by the
Compensation Committees consultant tests and influences
our future goal-setting process.
|
|
The Company has strong compensation governance practices,
including independent verification of financial goal achievement.
|
|
The Compensation Committee has established stock ownership
requirements for all officers of the Company.
|
|
Our plan provisions require recoupment of awards under certain
circumstances.
|
No reporting person failed to file, on a timely basis, the
reports required by Section 16(a) of the Securities
Exchange Act of 1934, as amended.
Mr. Francis S. Blake, a former Director, and
Mr. Donald M. James are the Chief Executive Officers of The
Home Depot, Inc. and Vulcan Materials Company, respectively.
During 2009, subsidiaries of the Company purchased goods and
services in the amount of approximately approximately $502,000
from The Home Depot, Inc. and approximately $544,000 from Vulcan
Materials Company. These amounts represented numerous individual
purchases from The Home Depot, Inc. and several individual
transactions with Vulcan Materials Company.
64
During 2009, Mr. David Huddleston and Mr. William
Allen,
sons-in-law
of Mr. Michael D. Garrett, an executive officer of the
Company, were both employed at subsidiaries of the Company.
Mr. Huddleston was employed by Alabama Power as an
Engineering Supervisor and received compensation in 2009 of
$132,838. Mr. Allen was employed by Southern Company
Services, Inc. as a Team Leader and received compensation in
2009 of $129,532.
The Company does not have a written policy pertaining solely to
the approval or ratification of related party
transactions. However, the Company has a Code of Ethics as
well as employment and compensation policies that govern the
hiring and compensating of all employees, including those named
above. The Company also has a Contract Guidance Manual and other
formal written procurement policies and procedures that guide
the purchase of goods and services, including requiring
competitive bids for most transactions above $10,000 or approval
based on documented business needs for sole sourcing
arrangements.
65
APPENDIX A
PROPOSED
AMENDMENT TO THE COMPANYS BY-LAWS
6. Each stockholder entitled to vote in accordance with the
Certificate of Incorporation or any amendment thereof and in
accordance with the provisions of these By-Laws or of any action
taken pursuant thereto shall be entitled to one vote, in person
or by proxy, for each share of stock entitled to vote held by
such stockholder, but no proxy shall be voted on after three
years from its date unless such proxy provides for a longer
period. Except where the transfer books of the Corporation shall
have been closed or a date shall have been fixed as a record
date for the determination of its stockholders entitled to vote,
as hereinafter provided, no share of stock shall be voted on at
any election for directors which shall have been transferred on
the books of the Corporation within 20 days next preceding
such election of directors. The vote for directors, and, upon
the demand of any stockholder, the vote upon any question before
the meeting, shall be by ballot. Each director shall be elected
by the vote of the majority of the votes cast with respect to
the director at any meeting for the election of directors at
which a quorum is present; provided that if the number of
nominees exceeds the number of directors to be elected,
directors shall be elected by a plurality vote and each
stockholder shall be entitled to as many votes as shall equal
the number of his shares of stock multiplied by the number of
directors to be elected, and he may cast all of such votes for a
single director or may distribute them among the number to be
voted for, or any two or more of them as he may see fit, which
right when exercised shall be termed cumulative voting. All
other questions shall be decided by plurality vote except as
otherwise provided by the Certificate of Incorporation
and/or by
the laws of the State of Delaware. For purposes of this
Section 6, a majority of the votes cast means that the
number of shares voted for the election of a
director must exceed the number of votes cast
against the election of that director.
APPENDIX B
POLICY ON
ENGAGEMENT OF THE INDEPENDENT AUDITOR
FOR AUDIT AND NON-AUDIT SERVICES
|
|
A. |
Southern Company (including its subsidiaries) will not engage
the independent auditor to perform any services that are
prohibited by the Sarbanes-Oxley Act of 2002. It shall further
be the policy of the Company not to retain the independent
auditor for non-audit services unless there is a compelling
reason to do so and such retention is otherwise pre-approved
consistent with this policy. Non-audit services that are
prohibited include:
|
|
|
|
|
1.
|
Bookkeeping and other services related to the preparation of
accounting records or financial statements of the Company or its
subsidiaries.
|
|
|
2.
|
Financial information systems design and implementation.
|
|
|
3.
|
Appraisal or valuation services, fairness opinions, or
contribution-in-kind
reports.
|
|
|
4.
|
Actuarial services.
|
|
|
5.
|
Internal audit outsourcing services.
|
|
|
6.
|
Management functions or human resources.
|
|
|
7.
|
Broker or dealer, investment adviser, or investment banking
services.
|
|
|
8.
|
Legal services or expert services unrelated to financial
statement audits.
|
|
|
9.
|
Any other service that the Public Company Accounting Oversight
Board determines, by regulation, is impermissible.
|
|
|
B.
|
Effective January 1, 2003, officers of the Company
(including its subsidiaries) may not engage the independent
auditor to perform any personal services, such as personal
financial planning or personal income tax services.
|
|
C.
|
All audit services (including providing comfort letters and
consents in connection with securities issuances) and
permissible non-audit services provided by the independent
auditor must be pre-approved by the Southern Company Audit
Committee.
|
|
D.
|
Under this Policy, the Audit 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
Table of Contents
|
|
|
|
|
|
|
|
|
|
Southern Company Common Stock and Dividend Information
|
|
|
ii
|
|
|
|
|
|
|
|
Five-Year Cumulative Performance Graph
|
|
|
ii
|
|
|
|
|
|
|
|
Ten-Year Cumulative Performance Graph
|
|
|
iii
|
|
|
|
|
|
|
|
Managements Report on Internal Control over Financial
Reporting
|
|
|
C-1
|
|
|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
C-2
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of Financial Condition
and Results of Operations
|
|
|
C-3
|
|
|
|
|
|
|
|
Quantitative and Qualitative Disclosures about Market Risk
|
|
|
C-27
|
|
|
|
|
|
|
|
Cautionary Statement Regarding Forward-Looking Statements
|
|
|
C-31
|
|
|
|
|
|
|
|
Consolidated Statements of Income
|
|
|
C-32
|
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows
|
|
|
C-33
|
|
|
|
|
|
|
|
Consolidated Balance Sheets
|
|
|
C-34
|
|
|
|
|
|
|
|
Consolidated Statements of Capitalization
|
|
|
C-36
|
|
|
|
|
|
|
|
Consolidated Statements of Common Stockholders Equity
|
|
|
C-38
|
|
|
|
|
|
|
|
Consolidated Statements of Comprehensive Income
|
|
|
C-39
|
|
|
|
|
|
|
|
Notes to Financial Statements
|
|
|
C-40
|
|
|
|
|
|
|
|
Selected Consolidated Financial and Operating Data
|
|
|
C-87
|
|
|
|
|
|
|
|
Management Council
|
|
|
C-89
|
|
|
|
|
|
|
|
Stockholder Information
|
|
|
C-91
|
|
|
i
SOUTHERN
COMPANY COMMON STOCK AND DIVIDEND INFORMATION
The common stock of Southern Company is listed and traded on the
New York Stock Exchange. The common stock is also traded on
regional exchanges across the United States. The high and low
stock prices as reported on the New York Stock Exchange for each
quarter of the past two years were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
Low
|
|
Dividend
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
37.62
|
|
|
$
|
26.48
|
|
|
$
|
0.4200
|
|
Second Quarter
|
|
|
32.05
|
|
|
|
27.19
|
|
|
|
0.4375
|
|
Third Quarter
|
|
|
32.67
|
|
|
|
30.27
|
|
|
|
0.4375
|
|
Fourth Quarter
|
|
|
34.47
|
|
|
|
30.89
|
|
|
|
0.4375
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
40.60
|
|
|
$
|
33.71
|
|
|
$
|
0.4025
|
|
Second Quarter
|
|
|
37.81
|
|
|
|
34.28
|
|
|
|
0.4200
|
|
Third Quarter
|
|
|
40.00
|
|
|
|
34.46
|
|
|
|
0.4200
|
|
Fourth Quarter
|
|
|
38.18
|
|
|
|
29.82
|
|
|
|
0.4200
|
|
|
On March 31, 2010, Southern Company had approximately
91,598 registered stockholders.
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, 2004 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.
ii
TEN-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
10 years. The graph assumes that $100 was invested on
December 31, 1999 in the Companys Common Stock and
each of the above indices and that all dividends were
reinvested. The stockholder return shown below for the
10-year
historical period may not be indicative of future performance.
iii
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2009 Annual Report
Southern Companys management is responsible for establishing and maintaining an
adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act
of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only
reasonable, not absolute, assurance that the objectives of the control system are met.
Under 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 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, 2009.
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, 2009. Deloitte & Touche
LLPs report on Southern Companys internal control over financial reporting is included herein.
/s/ David M. Ratcliffe
David M. Ratcliffe
Chairman, President, and Chief Executive Officer
/s/ W. Paul Bowers
W. Paul Bowers
Executive Vice President and Chief Financial Officer
February 25, 2010
C-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Southern Company
We have audited the accompanying consolidated balance sheets and consolidated statements of
capitalization of Southern Company and Subsidiary Companies (the Company) as of December 31, 2009
and 2008, and the related consolidated statements of income, comprehensive income, stockholders
equity, and cash flows for each of the three years in the period ended December 31, 2009. We also
have audited the Companys internal control over financial reporting as of December 31, 2009, based
on criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The 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 C-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 C-32 to C-85) referred to above
present fairly, in all material respects, the financial position of Southern Company and Subsidiary
Companies as of December 31, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion,
the Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2009, based on the criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 25, 2010
C-2
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2009 Annual Report
OVERVIEW
Business Activities
The primary business of Southern Company (the Company) is electricity sales in the Southeast
by the traditional operating companies Alabama Power, Georgia Power, Gulf Power, and Mississippi
Power and Southern Power. The four traditional operating companies are vertically integrated
utilities providing electric service in four Southeastern states. Southern Power constructs,
acquires, owns, and manages generation assets and sells electricity at market-based rates in the
wholesale market.
Many factors affect the opportunities, challenges, and risks of Southern Companys electricity
business. These factors include the traditional operating companies ability to maintain a
constructive regulatory environment, to maintain energy sales given the effects of the recession,
and to effectively manage and secure timely recovery of rising costs. Each of the traditional
operating companies has various regulatory mechanisms that operate to address cost recovery.
Appropriately balancing required costs and capital expenditures with customer prices will continue
to challenge the Company for the foreseeable future.
Another major factor is the profitability of the competitive market-based wholesale generating
business and federal regulatory policy, which may impact Southern Companys level of participation
in this market. The Company continues to face regulatory challenges related to transmission issues
at the national level. Southern Power continues to execute its strategy through a combination of
acquiring and constructing new power plants and by entering into power purchase agreements (PPAs)
with investor owned utilities, independent power producers, municipalities, and electric
cooperatives.
Southern Companys other business activities include investments in leveraged lease projects,
renewable energy projects, and telecommunications. Management continues to evaluate the
contribution of each of these activities to total shareholder return and may pursue acquisitions
and dispositions accordingly.
Key Performance Indicators
In striving to maximize shareholder value while providing cost-effective energy to more than four
million customers, Southern Company continues to focus on several key indicators. These indicators
include customer satisfaction, plant availability, system reliability, and earnings per share
(EPS), excluding the MC Asset Recovery, LLC (MC Asset Recovery) litigation settlement discussed
below. Southern Companys financial success is directly tied to the satisfaction of its customers.
Key elements of ensuring customer satisfaction include outstanding service, high reliability, and
competitive prices. Management uses customer satisfaction surveys and reliability indicators to
evaluate the Companys results.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro and
nuclear plant availability and efficient generation fleet operations during the months when
generation needs are greatest. The rate is calculated by dividing the number of hours of forced
outages by total generation hours. The fossil/hydro 2009 Peak Season EFOR of 1.44% was better than
the target. The nuclear 2009 Peak Season EFOR of 2.61% was slightly better than the target.
Transmission and distribution system reliability performance is measured by the frequency and
duration of outages. Performance targets for reliability are set internally based on historical
performance, expected weather conditions, and expected capital expenditures. The performance for
2009 was better than the target for these reliability measures.
Southern Company entered into a settlement agreement with MC Asset Recovery to resolve a complaint
alleging that Southern Company caused Mirant Corporation (Mirant) to engage in certain fraudulent
transfers and to pay illegal dividends to Southern Company prior to the spin-off of Mirant in 2001.
Pursuant to the settlement, Southern Company recorded a charge of $202 million in 2009. The
settlement has been completed and resolves all claims by MC Asset Recovery against Southern
Company. Southern Company management uses the non-GAAP (defined below) measure of EPS, excluding
the MC Asset Recovery litigation settlement, to evaluate the performance of Southern Companys
ongoing business activities. Southern Company believes the presentation of this non-GAAP measure
of earnings and EPS excluding the MC Asset Recovery litigation settlement is useful for investors
because it provides earnings information that is consistent with the historical and ongoing
business activities of the Company. The presentation of this information is not meant to be
considered a substitute for financial measures prepared in accordance with generally accepted
accounting principles (GAAP).
C-3
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Southern Companys 2009 results compared with its targets for some of these key indicators are
reflected in the following chart:
|
|
|
|
|
|
|
|
|
2009 Target |
|
2009 Actual |
Key Performance Indicator |
|
Performance |
|
Performance |
|
|
Top quartile in |
|
|
Customer Satisfaction |
|
customer surveys |
|
Top quartile |
Peak Season EFOR fossil/hydro |
|
2.75% or less |
|
|
1.44 |
% |
Peak Season EFOR nuclear |
|
2.75% or less |
|
|
2.61 |
% |
Basic EPS |
|
$2.30 $2.45 |
|
$ |
2.07 |
|
EPS, excluding the MC Asset Recovery litigation settlement |
|
|
|
$ |
2.32 |
|
See RESULTS OF OPERATIONS herein for additional information on the Companys financial performance.
The performance achieved in 2009 reflects the continued emphasis that management places on these
indicators as well as the commitment shown by employees in achieving or exceeding managements
expectations.
Earnings
Southern Companys net income after dividends on preferred and preference stock of subsidiaries was
$1.64 billion in 2009, a decrease of $99 million from the prior year. This decrease was primarily
the result of a litigation settlement with MC Asset Recovery, a decrease in revenues from lower
kilowatt-hour (KWH) demand across all customer classes, a decrease in revenues from market-response
rates to large commercial and industrial customers, higher depreciation and amortization, higher
interest expense, and unfavorable weather. The 2009 decrease was partially offset by an increase
in revenues from customer charges at Alabama Power, increased recognition of environmental
compliance cost recovery (ECCR) revenues at Georgia Power in accordance with its retail rate plan
for the years 2008 through 2010 (2007 Retail Rate Plan), lower operations and maintenance expenses,
an increase in allowance for funds used during construction (AFUDC) equity, which is not taxable, a
2008 charge related to the tax treatment of leveraged lease investments, and a gain on the early
retirement of two international leveraged lease investments. Net income after dividends on
preferred and preference stock of subsidiaries was $1.74 billion in 2008 and $1.73 billion in 2007.
Basic EPS was $2.07 in 2009, $2.26 in 2008, and $2.29 in 2007. Diluted EPS, which factors in
additional shares related to stock-based compensation, was $2.06 in 2009, $2.25 in 2008, and $2.28
in 2007.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of
common stock were $1.7325 in 2009, $1.6625 in 2008, and $1.595 in 2007. In January 2010, Southern
Company declared a quarterly dividend of 43.75 cents per share. This is the 249th consecutive
quarter that Southern Company has paid a dividend equal to or higher than the previous quarter.
The Company targets a dividend payout ratio of approximately 65% to 70% of net income. For 2009,
the actual payout ratio was 83.3% while the payout ratio of net income excluding the MC Asset
Recovery litigation settlement was 74.2%.
C-4
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
RESULTS OF OPERATIONS
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
from Prior Year |
|
|
|
|
2009 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
(in millions) |
|
Electric operating revenues |
|
$ |
15,642 |
|
|
$ |
(1,358 |
) |
|
$ |
1,860 |
|
|
$ |
1,052 |
|
|
Fuel |
|
|
5,952 |
|
|
|
(865 |
) |
|
|
973 |
|
|
|
701 |
|
Purchased power |
|
|
474 |
|
|
|
(341 |
) |
|
|
300 |
|
|
|
(28 |
) |
Other operations and maintenance |
|
|
3,401 |
|
|
|
(183 |
) |
|
|
111 |
|
|
|
183 |
|
Depreciation and amortization |
|
|
1,476 |
|
|
|
62 |
|
|
|
199 |
|
|
|
51 |
|
Taxes other than income taxes |
|
|
816 |
|
|
|
22 |
|
|
|
56 |
|
|
|
23 |
|
|
Total electric operating expenses |
|
|
12,119 |
|
|
|
(1,305 |
) |
|
|
1,639 |
|
|
|
930 |
|
|
Operating income |
|
|
3,523 |
|
|
|
(53 |
) |
|
|
221 |
|
|
|
122 |
|
Other income (expense), net |
|
|
199 |
|
|
|
53 |
|
|
|
26 |
|
|
|
66 |
|
Interest expense, net of amounts
capitalized |
|
|
834 |
|
|
|
61 |
|
|
|
10 |
|
|
|
46 |
|
Income taxes |
|
|
988 |
|
|
|
(49 |
) |
|
|
87 |
|
|
|
1 |
|
|
Net income |
|
|
1,900 |
|
|
|
(12 |
) |
|
|
150 |
|
|
|
141 |
|
Dividends on preferred and
preference stock of subsidiaries |
|
|
65 |
|
|
|
|
|
|
|
17 |
|
|
|
13 |
|
|
Net income after dividends on
preferred and preference stock
of subsidiaries |
|
$ |
1,835 |
|
|
$ |
(12 |
) |
|
$ |
133 |
|
|
$ |
128 |
|
|
Electric Operating Revenues
Details of electric operating revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
(in millions) |
Retail prior year |
|
$ |
14,055 |
|
|
$ |
12,639 |
|
|
$ |
11,801 |
|
Estimated change in |
|
|
|
|
|
|
|
|
|
|
|
|
Rates and pricing |
|
|
144 |
|
|
|
668 |
|
|
|
161 |
|
Sales growth (decline) |
|
|
(208 |
) |
|
|
|
|
|
|
60 |
|
Weather |
|
|
(21 |
) |
|
|
(106 |
) |
|
|
54 |
|
Fuel and other cost recovery |
|
|
(663 |
) |
|
|
854 |
|
|
|
563 |
|
|
Retail current year |
|
|
13,307 |
|
|
|
14,055 |
|
|
|
12,639 |
|
Wholesale revenues |
|
|
1,802 |
|
|
|
2,400 |
|
|
|
1,988 |
|
Other electric operating revenues |
|
|
533 |
|
|
|
545 |
|
|
|
513 |
|
|
Electric operating revenues |
|
$ |
15,642 |
|
|
$ |
17,000 |
|
|
$ |
15,140 |
|
|
Percent change |
|
|
(8.0 |
%) |
|
|
12.3 |
% |
|
|
7.5 |
% |
|
C-5
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Retail revenues decreased $748 million, increased $1.4 billion, and increased $838 million in 2009,
2008, and 2007, respectively. The significant factors driving these changes are shown in the
preceding table. The increase in rates and pricing in 2009 was primarily due to an increase in
revenues from customer charges at Alabama Power and increased recognition of ECCR revenues at
Georgia Power in accordance with its 2007 Retail Rate Plan, partially offset by a decrease in
revenues from market-response rates to large commercial and industrial customers at Georgia Power.
The 2008 increase in rates and pricing when compared to the prior year was primarily due to Alabama
Powers increase under its Rate Stabilization and Equalization Plan (Rate RSE), as ordered by the
Alabama Public Service Commission (PSC), and Georgia Powers increase under its 2007 Retail Rate
Plan, as ordered by the Georgia PSC. Also contributing to the 2008 increase was an increase in
revenues from market-response rates to large commercial and industrial customers. The 2007
increase in rates and pricing when compared to the prior year was primarily due to Alabama Powers
increase under its Rate RSE, as ordered by the Alabama PSC. Partially offsetting the 2007 increase
was a decrease in revenues from market-response rates to large commercial and industrial customers.
See Energy Sales below for a discussion of changes in the volume of energy sold, including
changes related to sales growth (decline) and weather.
Electric rates for the traditional operating companies include provisions to adjust billings for
fluctuations in fuel costs, including the energy component of purchased power costs. Under these
provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased
power, and do not affect net income. The traditional operating companies may also have one or more
regulatory mechanisms to recover other costs such as environmental, storm damage, new plants, and
PPAs.
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit
power sales contracts, and short-term opportunity sales. Short-term opportunity sales are made at
market-based rates that generally provide a margin above the Companys variable cost to produce the
energy.
In 2009, wholesale revenues decreased $598 million. Wholesale fuel revenues, which are generally
offset by wholesale fuel expenses and do not affect net income, decreased $603 million in 2009.
Excluding wholesale fuel revenues, wholesale revenues increased $5 million primarily due to
additional revenues associated with a new PPA at Southern Powers Plant Franklin Unit 3 which began
in January 2009, partially offset by fewer short-term opportunity sales due to lower gas prices and
reduced margins on short-term opportunity sales.
In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the
average cost of fuel per net KWH generated, as well as revenues resulting from new and existing
PPAs and revenues derived from contracts for Southern Powers Plant Oleander Unit 5 and Plant
Franklin Unit 3 placed in operation in December 2007 and June 2008, respectively. The 2008
increase was partially offset by a decrease in short-term opportunity sales and weather-related
generation load reductions.
In 2007, wholesale revenues increased $166 million primarily as a result of a 9.5% increase in the
average cost of fuel per net KWH generated. Excluding fuel, wholesale revenues were flat when
compared to the prior year.
Revenues associated with PPAs and opportunity sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
(in millions) |
|
Other power sales |
|
|
|
|
|
|
|
|
|
|
|
|
Capacity and other |
|
$ |
575 |
|
|
$ |
538 |
|
|
$ |
533 |
|
Energy |
|
|
735 |
|
|
|
1,319 |
|
|
|
989 |
|
|
Total |
|
$ |
1,310 |
|
|
$ |
1,857 |
|
|
$ |
1,522 |
|
|
C-6
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect
the recovery of fixed costs and a return on investment. Unit power KWH sales decreased 7.5%, 2.1%,
and 0.8% in 2009, 2008, and 2007, respectively. Fluctuations in oil and natural gas prices, which
are the primary fuel sources for unit power sales contracts, influence changes in these sales. See
FUTURE EARNINGS POTENTIAL PSC Matters Alabama Power herein for additional information
regarding the termination of certain unit power sales contracts in 2010. However, because the
energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings.
The capacity and energy components of the unit power sales contracts were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
(in millions) |
|
Unit power sales |
|
|
|
|
|
|
|
|
|
|
|
|
Capacity |
|
$ |
225 |
|
|
$ |
223 |
|
|
$ |
202 |
|
Energy |
|
|
267 |
|
|
|
320 |
|
|
|
264 |
|
|
Total |
|
$ |
492 |
|
|
$ |
543 |
|
|
$ |
466 |
|
|
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to
year. KWH sales for 2009 and the percent change by year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KWHs |
|
|
Percent Change |
|
|
|
|
|
|
2009 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
(in billions) |
|
Residential |
|
|
51.7 |
|
|
|
(1.1 |
)% |
|
|
(2.0 |
)% |
|
|
1.8 |
% |
Commercial |
|
|
53.5 |
|
|
|
(1.7 |
) |
|
|
(0.4 |
) |
|
|
3.2 |
|
Industrial |
|
|
46.4 |
|
|
|
(11.8 |
) |
|
|
(3.7 |
) |
|
|
(0.7 |
) |
Other |
|
|
1.0 |
|
|
|
2.0 |
|
|
|
(2.9 |
) |
|
|
4.4 |
|
|
Total retail |
|
|
152.6 |
|
|
|
(4.8 |
) |
|
|
(2.1 |
) |
|
|
1.4 |
|
Wholesale |
|
|
33.5 |
|
|
|
(14.9 |
) |
|
|
(3.4 |
) |
|
|
5.9 |
|
|
Total energy sales |
|
|
186.1 |
|
|
|
(6.8 |
) |
|
|
(2.3 |
) |
|
|
2.3 |
|
|
Changes in retail energy sales are comprised of changes in electricity usage by customers, changes
in weather, and changes in the number of customers. Retail energy sales decreased 7.7 billion KWHs
in 2009 primarily as a result of lower usage by industrial customers due to the recessionary
economy. Reduced demand in the primary metal, chemical, and textile sectors, as well as the stone,
clay, and glass sector, contributed most significantly to the decrease in industrial KWH sales.
Unfavorable weather also contributed to lower KWH sales across all customer classes. The number of
customers in 2009 was flat compared to 2008. Retail energy sales in 2008 decreased 3.4 billion
KWHs as a result of a 1.4% decrease in electricity usage mainly due to a slowing economy that
worsened during the fourth quarter. The 2008 decrease in residential sales resulted primarily from
lower home occupancy rates in Southern Companys service area when compared to 2007. Throughout
the year, reduced demand in the textile sector, the lumber sector, and the stone, clay, and glass
sector contributed to the decrease in 2008 industrial sales. Additional weakness in the fourth
quarter 2008 affected all major industrial segments. Significantly less favorable weather in 2008
when compared to 2007 also contributed to the 2008 decrease in retail energy sales. These
decreases were partially offset by customer growth of 0.6%. Retail energy sales in 2007 increased
2.3 billion KWHs as a result of 1.3% customer growth and favorable weather in 2007 when compared to
2006. The 2007 decrease in industrial sales primarily resulted from reduced demand and closures
within the textile sector, as well as decreased demand in the primary metals sector and the stone,
clay, and glass sector.
Wholesale energy sales decreased by 5.9 billion KWHs in 2009, decreased by 1.4 billion KWHs in
2008, and increased by 2.3 billion KWHs in 2007. The decrease in wholesale energy sales in 2009
was primarily related to fewer short-term opportunity sales driven by lower gas prices and fewer
uncontracted generating units at Southern Power available to sell electricity on the wholesale
market. The decrease in wholesale energy sales in 2008 was primarily related to longer planned
maintenance outages at a fossil unit in 2008 as compared to 2007 which reduced the availability of
this unit for wholesale sales. Lower short-term opportunity sales primarily related to higher coal
prices also contributed to the 2008 decrease. These decreases were partially offset by Plant
Oleander Unit 5 and Plant Franklin Unit 3 being placed in operation in December 2007 and June 2008,
respectively. The increase in wholesale energy sales in 2007 was primarily related to new PPAs
acquired by Southern Company through the acquisition of Plant Rowan in September 2006, as well as
new contracts with EnergyUnited Electric Membership Corporation that commenced in September 2006
and January 2007. An increase in KWH sales under existing PPAs also contributed to the 2007
increase.
C-7
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel
sources for generation of electricity is determined primarily by demand, the unit cost of fuel
consumed, and the availability of generating units. Additionally, the electric utilities purchase
a portion of their electricity needs from the wholesale market. Details of electricity generated
and purchased by the electric utilities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
Total generation (billions of KWHs) |
|
|
187 |
|
|
|
198 |
|
|
|
206 |
|
Total purchased power (billions of KWHs) |
|
|
8 |
|
|
|
11 |
|
|
|
8 |
|
|
Sources of generation (percent) |
|
|
|
|
|
|
|
|
|
|
|
|
Coal |
|
|
57 |
|
|
|
68 |
|
|
|
70 |
|
Nuclear |
|
|
16 |
|
|
|
15 |
|
|
|
14 |
|
Gas |
|
|
23 |
|
|
|
16 |
|
|
|
15 |
|
Hydro |
|
|
4 |
|
|
|
1 |
|
|
|
1 |
|
|
Cost of fuel, generated (cents per net KWH) |
|
|
|
|
|
|
|
|
|
|
|
|
Coal |
|
|
3.70 |
|
|
|
3.27 |
|
|
|
2.61 |
|
Nuclear |
|
|
0.55 |
|
|
|
0.50 |
|
|
|
0.50 |
|
Gas |
|
|
4.58 |
|
|
|
7.58 |
|
|
|
6.64 |
|
|
Average cost of fuel, generated (cents per net KWH)* |
|
|
3.38 |
|
|
|
3.52 |
|
|
|
2.89 |
|
Average cost of purchased power (cents per net KWH) |
|
|
6.37 |
|
|
|
7.85 |
|
|
|
7.20 |
|
|
|
|
|
* |
|
Fuel includes fuel purchased by the Company for tolling agreements where
power is generated by the provider and is included in purchased power when determining the average cost of purchased power. |
In 2009, fuel and purchased power expenses were $6.4 billion, a decrease of $1.2 billion or
15.8% below 2008 costs. This decrease was primarily the result of an
$839 million decrease related
to the total KWHs generated and purchased due primarily to lower customer demand. Also
contributing to this decrease was a $367 million reduction in the average cost of fuel and
purchased power resulting primarily from a 39.6% decrease in the cost of gas per KWH generated.
In 2008, fuel and purchased power expenses were $7.6 billion, an increase of $1.3 billion or 20.0%
above 2007 costs. This increase was primarily the result of a $1.3 billion net increase in the
average cost of fuel and purchased power partially resulting from a 25.3% increase in the cost of
coal per net KWH generated and a 14.2% increase in the cost of gas per net KWH generated.
In 2007, fuel and purchased power expenses were $6.4 billion, an increase of $673 million or 11.8%
above 2006 costs. This increase was primarily the result of a $543 million net increase in the
average cost of fuel and purchased power partially resulting from a 51.4% decrease in hydro
generation as a result of a severe drought. Also contributing to this increase was a $130 million
increase related to higher net KWHs generated and purchased.
Coal prices continued to be influenced by worldwide demand from developing countries, as well as
increased mining and fuel transportation costs. While coal prices reached unprecedented high
levels in 2008, the recessionary economy pushed prices downward in 2009. However, the lower prices
did not fully offset the higher priced coal already in inventory and under long-term contract.
Demand for natural gas in the United States also was affected by the recessionary economy leading
to significantly lower natural gas prices. During 2009, uranium prices continued to moderate from
the highs set during 2007. Worldwide production levels increased in 2009; however, secondary
supplies and inventories were still required to meet worldwide reactor demand.
Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the
traditional operating companies fuel cost recovery provisions. See FUTURE EARNINGS POTENTIAL
PSC Matters Fuel Cost Recovery herein for additional information. Likewise, Southern Powers
PPAs generally provide that the purchasers are responsible for substantially all of the cost of
fuel.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses were $3.4 billion, $3.6 billion, and $3.5 billion,
decreasing $183 million, increasing $111 million, and increasing $183 million in 2009, 2008, and
2007, respectively. Discussion of significant variances for components of other operations and
maintenance expenses follows.
C-8
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Other production expenses at fossil, hydro, and nuclear plants decreased $70 million, increased $63
million, and increased $128 million in 2009, 2008, and 2007, respectively. Production expenses
fluctuate from year to year due to variations in outage schedules and normal changes in the cost of
labor and materials. Other production costs decreased in 2009 mainly due to a $104 million
decrease related to less planned spending on outages and maintenance, as well as other cost
containment activities, which were the results of efforts to offset the effects of the recessionary
economy. The 2009 decrease was partially offset by a $6 million increase related to new
facilities, a $5 million loss on the transfer of Southern Powers Plant Desoto in 2009, a $6
million gain recognized in 2008 by Southern Power on the sale of an undeveloped tract of land to
the Orlando Utilities Commission (OUC), and a $17 million increase in nuclear refueling costs. See
Note 1 to the financial statements under Property, Plant, and Equipment for additional
information regarding nuclear refueling costs. Other production expenses increased in 2008
primarily due to a $64 million increase related to expenses incurred for maintenance outages at
generating units and a $30 million increase related to labor and materials expenses, partially
offset by a $15 million decrease in nuclear refueling costs. The 2008 increase was also partially
offset by a $24 million decrease related to new facilities, mainly lower costs associated with the
2007 write-off of Southern Powers integrated coal gasification combined cycle (IGCC) project with
the OUC. Other production expenses increased in 2007 primarily due to a $40 million increase
related to expenses incurred for maintenance outages at generating units and a $29 million increase
related to new facilities, mainly costs associated with the write-off of Southern Powers IGCC
project and the acquisitions of Plants DeSoto and Rowan by Southern Power in June and September
2006, respectively. A $25 million increase related to labor and materials expenses and a $22
million increase in nuclear refueling costs also contributed to the 2007 increase.
Transmission
and distribution expenses decreased $41 million, increased $4 million, and increased
$21 million in 2009, 2008, and 2007, respectively. Transmission and distribution expenses
fluctuate from year to year due to variations in maintenance schedules and normal changes in the
cost of labor and materials. Transmission and distribution expenses decreased in 2009 primarily
related to lower planned spending, as well as other cost containment activities. The 2008 increase
in transmission and distribution expenses was not material when compared to the prior year.
Transmission and distribution expenses increased in 2007 primarily as a result of increases in
labor and materials costs and maintenance associated with additional investment to meet customer
growth.
Customer sales and service expenses decreased $42 million, increased $32 million, and increased $7
million in 2009, 2008, and 2007, respectively. Customer sales and service expenses decreased in
2009 primarily as a result of a $12 million decrease in customer service expenses, an $8 million
decrease in meter reading expenses, a $10 million decrease in sales expenses, and a $7 million
decrease in customer records related expenses. The 2008 increase in customer sales and service
expenses was primarily a result of an increase in customer service expenses, including a $13
million increase in uncollectible accounts expense, a $9 million increase in meter reading
expenses, and an $8 million increase for customer records and collections. The 2007 increase in
customer sales and service expenses was not material when compared to the prior year.
Administrative and general expenses decreased $30 million, increased $12 million, and increased $27
million in 2009, 2008, and 2007, respectively. The 2009 decrease in administrative and general
expenses was primarily the result of cost containment activities which were the results of efforts
to offset the effects of the recessionary economy. The 2008 increase in administrative and general
expenses was not material when compared to 2007. Administrative and general expenses increased in
2007 primarily as a result of a $16 million increase in legal costs and expenses associated with an
increase in employees. Also contributing to the 2007 increase was a $14 million increase in
accrued expenses for the litigation and workers compensation reserve, partially offset by an $8
million decrease in property damage expense.
Depreciation and Amortization
Depreciation and amortization increased $62 million in 2009 primarily as a result of an increase in
plant in service related to environmental, transmission, and distribution projects mainly at
Alabama Power and Georgia Power and the completion of Southern Powers Plant Franklin Unit 3, as
well as an increase in depreciation rates at Southern Power. Partially offsetting the 2009
increase was a decrease associated with the amortization of the regulatory liability related to the
cost of removal obligations as authorized by the Georgia PSC. See Note 3 to the financial
statements under Retail Regulatory Matters Georgia Power Cost of Removal for additional
information regarding Georgia Powers cost of removal amortization.
Depreciation and amortization increased $199 million in 2008 primarily as a result of an increase
in plant in service related to environmental, transmission, and distribution projects mainly at
Alabama Power and Georgia Power and generation projects at Georgia Power. An increase in
depreciation rates at Georgia Power and Southern Power also contributed to the 2008 increase, as
well as the expiration of a rate order previously allowing Georgia Power to levelize certain
purchased power capacity costs and the completion of Plant Oleander Unit 5 in December 2007 and
Plant Franklin Unit 3 in June 2008.
C-9
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Depreciation and amortization increased $51 million in 2007 primarily as a result of an increase in
plant in service related to environmental, transmission, and distribution projects mainly at
Alabama Power and Georgia Power. An increase in the amortization expense of a regulatory liability
recorded in 2003 in connection with the Mississippi PSCs accounting order on Plant Daniel capacity
also contributed to the 2007 increase. Partially offsetting the 2007 increase was a reduction in
amortization expense due to a Georgia Power regulatory liability related to the levelization of
certain purchased power capacity costs as ordered by the Georgia PSC under the terms of the retail
rate order effective January 1, 2005. See Note 1 to the financial statements under Depreciation
and Amortization for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $22 million in 2009 primarily as a result of increases in
the bases of state and municipal public utility license taxes at Alabama Power and an increase in
franchise fees at Gulf Power. Increases in franchise fees are associated with increases in
revenues from energy sales. Taxes other than income taxes increased $56 million in 2008 primarily
as a result of increases in franchise fees and municipal gross receipt taxes associated with
increases in revenues from energy sales, as well as increases in property taxes associated with
property tax actualizations and additional plant in service. Taxes other than income taxes
increased $23 million in 2007 primarily as a result of increases in franchise and municipal gross
receipts taxes associated with increases in revenues from energy sales, partially offset by a
decrease in property taxes resulting from the resolution of a dispute with Monroe County, Georgia.
Other Income (Expense), Net
Other income (expense), net increased $53 million in 2009 primarily due to an increase in AFUDC
equity as a result of environmental projects at Alabama Power and Gulf Power and additional
investments in transmission and distribution projects at Alabama Power. In addition, during 2009,
Southern Power recognized a $13 million profit under a construction contract with the OUC whereby
Southern Power provided engineering, procurement, and construction services to build a combined
cycle unit. Other income (expense), net increased $26 million in 2008 primarily as a result of an
increase in AFUDC equity related to additional investments in environmental equipment at generating
plants at Alabama Power, Georgia Power, and Gulf Power, as well as additional investments in
transmission and distribution projects mainly at Alabama Power and Georgia Power. Other income
(expense), net increased $66 million in 2007 primarily as a result of an increase in AFUDC equity
related to additional investments in environmental equipment at generating plants and transmission
and distribution projects mainly at Alabama Power and Georgia Power.
Interest Expense, Net of Amounts Capitalized
Total interest charges and other financing costs increased by $61 million in 2009 primarily as a
result of a $100 million increase associated with $1.4 billion in additional debt outstanding at
December 31, 2009 compared to December 31, 2008. Also contributing to the 2009 increase was $16
million in other interest costs. The 2009 increase was partially offset by $42 million related to
lower average interest rates on existing variable rate debt and $13 million of additional
capitalized interest as compared to 2008.
Total interest charges and other financing costs increased by $10 million in 2008 primarily as a
result of a $65 million increase associated with $1.8 billion in additional debt outstanding at
December 31, 2008 compared to December 31, 2007. Also contributing to the 2008 increase was $5
million in other interest costs. The 2008 increase was partially offset by $55 million related to
lower average interest rates on existing variable rate debt and $7 million of additional
capitalized interest as compared to 2007.
Total interest charges and other financing costs increased by $46 million in 2007 primarily as a
result of a $59 million increase associated with $703 million in additional debt outstanding at
December 31, 2007 compared to December 31, 2006 and higher interest rates associated with the
issuance of new long-term debt. Also contributing to the 2007 increase was $7 million related to
higher average interest rates on existing variable rate debt and $19 million in other interest
costs. The 2007 increase was partially offset by $38 million of additional capitalized interest as
compared to 2006.
Income Taxes
Income taxes decreased $49 million in 2009 primarily due to lower pre-tax earnings as compared to
2008, an increase in AFUDC equity, which is not taxable, and an increase in the Internal Revenue
Code of 1986, as amended (Internal Revenue Code), Section 199 production activities deduction. See
Note 5 to the financial statements under Effective Tax Rate for additional information.
C-10
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Income taxes increased $87 million in 2008 primarily due to higher pre-tax earnings as compared to
2007 and a 2007 deduction for a Georgia Power land donation. The 2008 increase was partially
offset by an increase in AFUDC equity, which is not taxable.
Income taxes were relatively flat in 2007 as higher pre-tax earnings as compared to 2006 were
largely offset due to a deduction for a Georgia Power land donation; an increase in AFUDC equity,
which is not taxable; and an increase in the Section 199 production activities deduction.
Dividends on Preferred and Preference Stock of Subsidiaries
Dividends on preferred and preference stock of subsidiaries for 2009 were flat compared to the
prior year.
Dividends on preferred and preference stock of subsidiaries increased $17 million in 2008 primarily
as a result of issuances of $320 million and $150 million of preference stock in the third and
fourth quarters of 2007, respectively, partially offset by the redemption of $125 million of
preferred stock in January 2008.
Dividends on preferred and preference stock of subsidiaries increased $13 million in 2007 primarily
as a result of a $470 million increase associated with additional preference stock outstanding at
December 31, 2007 compared to December 31, 2006.
Other Business Activities
Southern Companys other business activities include the parent company (which does not allocate
operating expenses to business units), investments in leveraged lease projects, and
telecommunications. Southern Companys investment in synthetic fuel projects ended at December 31,
2007. These businesses are classified in general categories and may comprise one or more of the
following subsidiaries: Southern Company Holdings invests in various projects, including leveraged
lease projects; SouthernLINC Wireless provides digital wireless communications for use by Southern
Company and its subsidiary companies and also markets these services to the public and provides
fiber cable services within the Southeast.
A condensed statement of income for Southern Companys other business activities follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
Amount |
|
from Prior Year |
|
|
|
2009 |
|
2009 |
|
2008 |
|
2007 |
|
|
|
(in millions) |
Operating revenues |
|
$ |
101 |
|
|
$ |
(26 |
) |
|
$ |
(86 |
) |
|
$ |
(55 |
) |
|
Other operations and maintenance |
|
|
125 |
|
|
|
(40 |
) |
|
|
(44 |
) |
|
|
(29 |
) |
MC Asset Recovery litigation settlement |
|
|
202 |
|
|
|
202 |
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
27 |
|
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(6 |
) |
Taxes other than income taxes |
|
|
2 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
356 |
|
|
|
159 |
|
|
|
(45 |
) |
|
|
(35 |
) |
|
Operating income (loss) |
|
|
(255 |
) |
|
|
(185 |
) |
|
|
(41 |
) |
|
|
(20 |
) |
Equity in income (losses) of
unconsolidated subsidiaries |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
35 |
|
|
|
35 |
|
Leveraged lease income (losses) |
|
|
40 |
|
|
|
125 |
|
|
|
(125 |
) |
|
|
(29 |
) |
Other income (expense), net |
|
|
3 |
|
|
|
(8 |
) |
|
|
(31 |
) |
|
|
74 |
|
Interest expense |
|
|
71 |
|
|
|
(22 |
) |
|
|
(30 |
) |
|
|
(26 |
) |
Income taxes |
|
|
(92 |
) |
|
|
30 |
|
|
|
(7 |
) |
|
|
53 |
|
|
Net income (loss) |
|
$ |
(192 |
) |
|
$ |
(87 |
) |
|
$ |
(125 |
) |
|
$ |
33 |
|
|
Operating Revenues
Southern Companys non-electric operating revenues from these other businesses decreased $26
million in 2009 primarily as a result of a $25 million decrease in revenues at SouthernLINC
Wireless related to lower average revenue per subscriber and fewer subscribers due to increased
competition in the industry. The $86 million decrease in 2008 primarily resulted from a $60
million decrease associated with Southern Company terminating its investment in synthetic fuel
projects at December 31, 2007 and a $21 million decrease in revenues at SouthernLINC Wireless
related to lower average revenue per subscriber and fewer subscribers due to
C-11
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
increased competition in the industry. Also contributing to the 2008 decrease was a $5 million
decrease in revenues from Southern Companys energy-related services business. The $55 million
decrease in 2007 primarily resulted from a $14 million decrease in fuel procurement service
revenues following a contract termination, a $13 million decrease in revenues at SouthernLINC
Wireless related to lower average revenue per subscriber and fewer subscribers due to increased
competition in the industry, and an $11 million decrease in revenues from Southern Companys
energy-related services business.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other businesses decreased $40 million in 2009
primarily as a result of a $15 million decrease in salary and wages, advertising, equipment, and
network costs at SouthernLINC Wireless; a $10 million decrease in expenses associated with
leveraged lease litigation costs; and a $6 million decrease in parent company expenses associated
with the MC Asset Recovery litigation. Other operations and maintenance expenses decreased $44
million in 2008 primarily as a result of $11 million of lower coal expenses related to Southern
Company terminating its investment in synthetic fuel projects at December 31, 2007; $9 million of
lower sales expenses at SouthernLINC Wireless related to lower sales volume; and $5 million of
lower parent company expenses related to advertising, litigation, and property insurance costs.
Other operations and maintenance expenses decreased $29 million in 2007 primarily as a result of
$11 million of lower production expenses related to the termination of Southern Companys
membership interest in one of the synthetic fuel entities and $8 million attributed to the
wind-down of one of the Companys energy-related services businesses.
MC Asset Recovery Litigation Settlement
On March 31, 2009, Southern Company entered into a litigation settlement agreement with MC Asset
Recovery which resulted in a charge of $202 million and requires MC Asset Recovery to release
Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in
connection with Mirants plan of reorganization, as well as to release all actions against current
or former officers and directors of Mirant and Southern Company that have or could have been filed.
Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202
million, which was paid in the second quarter 2009. The settlement has been completed and resolves
all claims by MC Asset Recovery against Southern Company. On June 29, 2009, the case was dismissed
with prejudice.
Equity in Income (Losses) of Unconsolidated Subsidiaries
Southern Company made investments in two synthetic fuel production facilities that generated
operating losses. These investments allowed Southern Company to claim federal income tax credits
that offset these operating losses and made the projects profitable. Equity in income (losses) of
unconsolidated subsidiaries decreased $11 million in 2009 as a result of an $11 million gain
recognized in 2008 related to the dissolution of a partnership that was associated with these
synthetic fuel production facilities. Equity in income (losses) of unconsolidated subsidiaries
increased $35 million in 2008 primarily as a result of Southern Company terminating its investment
in synthetic fuel projects at December 31, 2007. Equity in income (losses) of unconsolidated
subsidiaries increased $35 million in 2007 primarily as a result of terminating Southern Companys
membership interest in one of the synthetic fuel entities which reduced the amount of the Companys
share of the losses and, therefore, the funding obligation for the year. Also contributing to the
2007 decrease were adjustments to the phase-out of the related federal income tax credits,
partially offset by higher operating expenses due to idled production in 2006 and decreased
production in 2007 in anticipation of exiting the business.
Leveraged Lease Income (Losses)
Southern Company has several leveraged lease agreements which relate to international and domestic
energy generation, distribution, and transportation assets. Southern Company receives federal
income tax deductions for depreciation and amortization, as well as interest on long-term debt
related to these investments. Leveraged lease income (losses) increased $125 million in 2009
primarily as a result of the application in 2008 of certain accounting standards related to
leveraged leases, as well as a $26 million gain recorded in the second quarter 2009 associated with
the early termination of two international leveraged lease investments. The proceeds from the
termination were required to be used to extinguish all debt related to leveraged lease investments,
a portion of which had make-whole redemption provisions. This resulted in a $17 million loss and
partially offset the 2009 increase. Leveraged lease income (losses) decreased $125 million in 2008
as a result of Southern Companys decision to participate in a settlement with the Internal Revenue
Service (IRS) related to deductions for several sale-in-lease-out transactions and the resulting
application of certain accounting standards related to leveraged leases. Leveraged lease income
(losses) decreased $29 million in 2007 as a result of the adoption of certain accounting standards
related to leveraged leases, as well as an expected decline in leveraged lease income over the
terms of the leases.
C-12
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Other Income (Expense), Net
The 2009 change in other income (expense), net for these other businesses when compared to the
prior year was not material. Other income (expense), net decreased $31 million in 2008 primarily
as a result of the 2007 gain on a derivative transaction in the synthetic fuel business which
settled on December 31, 2007. Other income (expense), net increased $74 million in 2007 primarily
as a result of a $60 million increase related to changes in the value of derivative transactions in
the synthetic fuel business and a $16 million increase related to the 2006 impairment of
investments in the synthetic fuel entities, partially offset by the release of $6 million in
certain contractual obligations associated with these investments in 2006.
Interest Expense
Total interest charges and other financing costs for these other businesses decreased $22 million
in 2009 primarily as a result of $26 million associated with lower average interest rates on
existing variable rate debt and a $2 million decrease attributed to other interest charges. The
2009 decrease was partially offset by a $4 million increase associated with $63 million in
additional debt outstanding at December 31, 2009 compared to December 31, 2008. Total interest
charges and other financing costs decreased $30 million in 2008 primarily as a result of
$29 million associated with lower average interest rates on existing variable rate debt and a $4
million decrease attributed to lower interest rates associated with new debt issued to replace
maturing securities. At December 31, 2008, these other businesses had $92 million in additional
debt outstanding compared to December 31, 2007. The 2008 decrease was partially offset by a $5
million increase in other interest costs. Total interest charges and other financing costs
decreased by $26 million in 2007 primarily as a result of $16 million of losses on debt that was
reacquired in 2006. Also contributing to the 2007 decrease was $97 million less debt outstanding
at December 31, 2007 compared to December 31, 2006, lower interest rates associated with the
issuance of new long-term debt, and a $4 million decrease in other interest costs.
Income Taxes
Income taxes for these other businesses increased $30 million in 2009 excluding the effects of the
$202 million charge resulting from the litigation settlement with MC Asset Recovery in the first
quarter 2009. The 2009 increase was primarily due to the application in 2008 of certain accounting
standards related to leveraged leases and income taxes. Partially offsetting this increase was
lower tax expense associated with the early termination of two international leveraged lease
investments and the extinguishment of the associated debt discussed previously under Leveraged
Lease Income (Losses). Income taxes decreased $7 million in 2008 primarily as a result of
leveraged lease losses discussed previously under Leveraged Lease Income (Losses), partially
offset by a $36 million decrease in net synthetic fuel tax credits as a result of Southern Company
terminating its investment in synthetic fuel projects at December 31, 2007. Income taxes increased
$53 million in 2007 primarily as a result of a $30 million decrease in net synthetic fuel tax
credits as a result of terminating Southern Companys membership interest in one of the synthetic
fuel entities in 2006 and increasing the synthetic fuel tax credit reserves due to an anticipated
phase-out of synthetic fuel tax credits due to higher oil prices. See Note 5 to the financial
statements under Effective Tax Rate for further information.
Effects of Inflation
The traditional operating companies are subject to rate regulation that is generally based on the
recovery of historical and projected costs. The effects of inflation can create an economic loss
since the recovery of costs could be in dollars that have less purchasing power. Southern Power is
party to long-term contracts reflecting market-based rates, including inflation expectations. Any
adverse effect of inflation on Southern Companys results of operations has not been substantial.
FUTURE EARNINGS POTENTIAL
General
The four traditional operating companies operate as vertically integrated utilities providing
electricity to customers within their service areas in the Southeastern United States. Prices for
electricity provided to retail customers are set by state PSCs under cost-based regulatory
principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the
exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC).
Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations.
Southern Power continues to focus on long-term capacity contracts, optimized by limited energy
trading activities. See ACCOUNTING POLICIES Application of Critical Accounting Policies and
Estimates Electric Utility Regulation herein and Note 3 to the financial statements for
additional information about regulatory matters.
C-13
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
The results of operations for the past three years are not necessarily indicative of future
earnings potential. The level of Southern Companys future earnings depends on numerous factors
that affect the opportunities, challenges, and risks of Southern Companys primary business of
selling electricity. These factors include the traditional operating companies ability to
maintain a constructive regulatory environment that continues to allow for the recovery of
prudently incurred costs during a time of increasing costs. Other major factors include the
profitability of the competitive wholesale supply business and federal regulatory policy which may
impact Southern Companys level of participation in this market. Southern Company continues to
face regulatory challenges related to transmission issues at the national level. Future earnings
for the electricity business in the near term will depend, in part, upon maintaining energy sales,
which is subject to a number of factors. These factors include weather, competition, new energy
contracts with neighboring utilities and other wholesale customers, energy conservation practiced
by customers, the price of electricity, the price elasticity of demand, and the rate of economic
growth or decline in the service area. In addition, the level of future earnings for the wholesale
supply business also depends on numerous factors including creditworthiness of customers, total
generating capacity available in the Southeast, future acquisitions and construction of generating
facilities, and the successful remarketing of capacity as current contracts expire. Recessionary
conditions have negatively impacted sales for the traditional operating companies, particularly to
industrial and commercial customers, and have negatively impacted wholesale capacity revenues at
Southern Power. The timing and extent of the economic recovery will impact future earnings.
Southern Company system generating capacity increased 325 megawatts due to Southern Powers
acquisition of West Georgia Generating Company, LLC and divestiture of DeSoto County Generating
Company, LLC in December 2009. In general, Southern Company has constructed or acquired new
generating capacity only after entering into long-term capacity contracts for the new facilities or
to meet requirements of Southern Companys regulated retail markets, both of which are optimized by
limited energy trading activities. See FUTURE EARNINGS POTENTIAL Construction Program herein
and Note 7 to the financial statements for additional information.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to
evaluate and consider a wide array of potential business strategies. These strategies may include
business combinations, partnerships, acquisitions involving other utility or non-utility businesses
or properties, disposition of certain assets, internal restructuring, or some combination thereof.
Furthermore, Southern Company may engage in new business ventures that arise from competitive and
regulatory changes in the utility industry. Pursuit of any of the above strategies, or any
combination thereof, may significantly affect the business operations, risks, and financial
condition of Southern Company.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations
could affect earnings if such costs cannot continue to be fully recovered in rates on a timely
basis. Environmental compliance spending over the next several years may exceed amounts estimated.
Some of the factors driving the potential for such an increase are higher commodity costs, market
demand for labor, and scope additions and clarifications. The timing, specific requirements, and
estimated costs could also change as environmental statutes and regulations are adopted or
modified. See Note 3 to the financial statements under Environmental Matters for additional
information.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S.
District Court for the Northern District of Georgia against certain Southern Company subsidiaries,
including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New
Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired
generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a
separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern
District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight
coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities
co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive
relief, including an order requiring installation of the best available control technology at the
affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi
Power relating to Gulf Powers Plant Crist and Mississippi Powers Plant Watson. In early 2000,
the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants
based on the allegations in the notices of violation. However, in March 2001, the court denied the
motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now
solely against Georgia Power, has been administratively closed since the spring of 2001, and the
case has not been reopened.
C-14
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree
between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the
alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern
District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its
other affected units regarding the proper legal test for determining whether projects are routine
maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision
did not resolve the case, which remains ongoing.
Southern Company believes that the traditional operating companies complied with applicable laws
and the EPA regulations and interpretations in effect at the time the work in question took place.
The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation
at each generating unit, depending on the date of the alleged violation. An adverse outcome could
require substantial capital expenditures or affect the timing of currently budgeted capital
expenditures that cannot be determined at this time and could possibly require payment of
substantial penalties. Such expenditures could affect future results of operations, cash flows,
and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
New York Case
In July 2004, three environmental groups and attorneys general from eight states, each outside of
Southern Companys service territory, and the corporation counsel for New York City filed
complaints in the U.S. District Court for the Southern District of New York against Southern
Company and four other electric power companies. The complaints allege that the companies
emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs
assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs
seek a judicial order (1) holding each defendant jointly and severally liable for creating,
contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap
its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year
for at least a decade. The plaintiffs have not, however, requested that damages be awarded in
connection with their claims. Southern Company believes these claims are without merit and notes
that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the
U.S. District Court for the Southern District of New York granted Southern Companys and the other
defendants motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of
Appeals for the Second Circuit in October 2005 and, on September 21, 2009, the U.S. Court of
Appeals for the Second Circuit reversed the district courts ruling, vacating the dismissal of the
plaintiffs claim, and remanding the case to the district court. On November 5, 2009, the
defendants, including Southern Company, sought rehearing en banc, and the courts ruling is subject
to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this
time.
Kivalina Case
In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S.
District Court for the Northern District of California against several electric utilities
(including Southern Company), several oil companies, and a coal company. The plaintiffs are the
governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being
destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions
of greenhouse gases by the defendants. The plaintiffs assert claims for public and private
nuisance and contend that some of the defendants have acted in concert and are therefore jointly
and severally liable for the plaintiffs damages. The suit seeks damages for lost property values
and for the cost of relocating the village, which is alleged to be $95 million to $400 million.
Southern Company believes that these claims are without merit and notes that the complaint cites no
statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for
the Northern District of California granted the defendants motions to dismiss the case based on
lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the
plaintiffs failure to establish the standard for determining that the defendants conduct caused
the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of
Appeals for the Ninth Circuit challenging the district courts order dismissing the case. The
ultimate outcome of this matter cannot be determined at this time.
Other Litigation
Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse
gas emissions have become more frequent, and courts have recently determined that private parties
and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of
Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of
Mississippis dismissal of private party claims against certain oil, coal, chemical, and utility
companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S.
Court of Appeals for the Fifth Circuit held that plaintiffs have standing to
C-15
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
assert their nuisance, trespass, and negligence claims and none of these claims are barred by the
political question doctrine. The Company is not currently a party to this litigation but the
traditional operating companies and Southern Power were named as defendants in an amended complaint
which was rendered moot in August 2007 by the U.S. District Court for the Southern District of
Mississippi when such court dismissed the original matter. The ultimate outcome of this matter
cannot be determined at this time.
Environmental Statutes and Regulations
General
The electric utilities operations are subject to extensive regulation by state and federal
environmental agencies under a variety of statutes and regulations governing environmental media,
including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean
Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource
Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community
Right-to-Know Act; the Endangered Species Act; and related federal and state regulations.
Compliance with these environmental requirements involves significant capital and operating costs,
a major portion of which is expected to be recovered through existing ratemaking provisions.
Through 2009, the electric utilities had invested approximately $7.5 billion in capital projects to
comply with these requirements, with annual totals of $1.3 billion, $1.6 billion, and $1.5 billion
for 2009, 2008, and 2007, respectively. The Company expects that capital expenditures to assure
compliance with existing and new statutes and regulations will be an additional $545 million, $721
million, and $1.2 billion for 2010, 2011, and 2012, respectively. The Companys compliance
strategy can be affected by changes to existing environmental laws, statutes, and regulations; the
cost, availability, and existing inventory of emissions allowances; and the Companys fuel mix.
Environmental costs that are known and estimable at this time are included in capital expenditures
discussed under FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual
Obligations herein.
Compliance with any new federal or state legislation or regulations related to global climate
change, air quality, coal combustion byproducts, including coal ash, or other environmental and
health concerns could also significantly affect Southern Company. Although new or revised
environmental legislation or regulations could affect many areas of Southern Companys operations,
the full impact of any such changes cannot be determined at this time.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a
significant focus for Southern Company. Through 2009, the electric utilities have spent
approximately $6.6 billion in reducing sulfur dioxide (SO2) and nitrogen oxide
(NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional
controls are currently being installed at several plants to further reduce air emissions, maintain
compliance with existing regulations, and meet new requirements.
The EPA regulates ground level ozone through implementation of an eight-hour ozone air quality
standard. A 20-county area within metropolitan Atlanta is the only location within Southern
Companys service area that is currently designated as nonattainment for the standard, which could
require additional reductions in NOx emissions from power plants. In March 2008,
however, the EPA issued a final rule establishing a more stringent eight-hour ozone standard, and
on January 6, 2010, the EPA proposed further reductions in the standard. The EPA is expected to
finalize the revised standard in August 2010 and require state implementation plans for any
nonattainment areas by December 2013. The revised eight-hour ozone standard is expected to result
in designation of new nonattainment areas within Southern Companys service territory.
During 2005, the EPAs annual fine particulate matter nonattainment designations became effective
for several areas within Southern Companys service area in Alabama and Georgia. State plans for
addressing the nonattainment designations for this standard could require further reductions in
SO2 and NOx emissions from power plants. In September 2006, the EPA
published a final rule which increased the stringency of the 24-hour average fine particulate
matter air quality standard. The Birmingham, Alabama area has been designated as nonattainment for
the 24-hour standard, and a state implementation plan for this nonattainment area is due in
December 2012.
On December 8, 2009, the EPA also proposed revisions to the National Ambient Air Quality Standard
for SO2. The EPA is expected to finalize the revised SO2 standard in June
2010.
Twenty-eight eastern states, including each of the states within Southern Companys service area,
are subject to the requirements of the Clean Air Interstate Rule (CAIR). The rule calls for
additional reductions of NOx and/or SO2 to be achieved in two phases,
2009/2010 and 2015. In July 2008 and December 2008, the U.S. Court of Appeals for the District of
Columbia Circuit issued
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
decisions invalidating certain aspects of CAIR, but left CAIR compliance requirements in place
while the EPA develops a revised rule. States in the Southern Company service territory have
completed plans to implement CAIR, and emissions reductions are being accomplished by the
installation of emissions controls at coal-fired facilities of the electric utilities and/or by the
purchase of emissions allowances. The EPA is expected to issue a proposed CAIR replacement rule in
July 2010.
The Clean Air Visibility Rule was finalized in July 2005, with a goal of restoring natural
visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064.
The rule involves the application of Best Available Retrofit Technology (BART) to certain sources
built between 1962 and 1977, and any additional emissions reductions necessary for each designated
area to achieve reasonable progress toward the natural conditions goal by 2018 and for each
ten-year period thereafter. For power plants, the Clean Air Visibility Rule allows states to
determine that CAIR satisfies BART requirements for SO2 and NOx, and no
additional controls beyond CAIR are anticipated to be necessary at any of the traditional operating
companies facilities. States have completed or are currently completing implementation plans for
BART compliance and other measures required to achieve the first phase of reasonable progress.
The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal and
oil-fired electric generating units, which will likely address numerous Hazardous Air Pollutants,
including mercury. In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), a cap and
trade program for the reduction of mercury emissions from coal-fired power plants. In February
2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. In a
separate proceeding in the U.S. District Court for the District of Columbia, the EPA entered into a
proposed consent decree that requires the EPA to issue a proposed MACT rule by March 16, 2011 and a
final rule by November 16, 2011.
In February 2004, the EPA finalized the Industrial Boiler (IB) MACT rule, which imposed limits on
hazardous air pollutants from industrial boilers, including biomass boilers. Compliance with the
final rule was scheduled to begin in September 2007; however, in response to challenges to the
final rule, the U.S. Court of Appeals for the District of Columbia Circuit vacated the IB MACT rule
in its entirety in July 2007 and ordered the EPA to develop a new IB MACT rule. In September 2009,
the deadline to promulgate a proposed rule was extended from July 15, 2009 to April 15, 2010, with
a final rule required by December 16, 2010. The EPA is currently developing the new rule and may
change the methodology to determine the MACT limits for industrial boilers.
The impacts of the eight-hour ozone standards, the fine particulate matter nonattainment
designations, and future revisions to CAIR, the SO2 standard, the Clean Air Visibility
Rule, and the MACT rules for electric generating units and industrial boilers on the Company cannot
be determined at this time and will depend on the specific provisions of the final rules,
resolution of any legal challenges, and the development and implementation of rules at the state
level. However, these additional regulations could result in significant additional compliance
costs that could affect future unit retirement and replacement decisions and results of operations,
cash flows, and financial condition if such costs are not recovered through regulated rates.
The Company has developed and continually updates a comprehensive environmental compliance strategy
to assess compliance obligations associated with the continuing and new environmental requirements
discussed above. As part of this strategy, the Company has already installed a number of SO2
and NOx emissions controls and plans to install additional controls within the
next several years to ensure continued compliance with applicable air quality requirements. In
addition, most units in Georgia are required to install specific emissions controls according to a
schedule set forth in the states Multipollutant Rule, which is designed to reduce emissions of
SO2, NOx, and mercury in Georgia.
Water Quality
In July 2004, the EPA published final regulations under the Clean Water Act to reduce impingement
and entrainment of fish, shellfish, and other forms of aquatic life at existing power plant cooling
water intake structures. The use of cost-benefit analysis in the rule was ultimately appealed to
the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court held that the EPA could consider
costs in arriving at its standards and in providing variances from those standards for existing
intake structures. The EPA is now in the process of revising the regulations. While the U.S.
Supreme Courts decision may ultimately result in greater flexibility for demonstrating compliance
with the standards, the full scope of the regulations will depend on further rulemaking by the EPA
and the actual requirements established by state regulatory agencies and, therefore, cannot be
determined at this time.
On December 28, 2009, the EPA announced its determination that revision of the current effluent
guidelines for steam electric power plants is warranted and proposed a plan to adopt such revisions
by 2013. New wastewater treatment requirements are expected and may result in the installation of
additional controls on certain Southern Company system facilities. The impact of revised
guidelines will depend on the studies conducted in connection with the rulemaking, as well as the
specific requirements of the final rule, and, therefore, cannot be determined at this time.
C-17
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Environmental Remediation
Southern Company must comply with other environmental laws and regulations that cover the handling
and disposal of waste and releases of hazardous substances. Under these various laws and
regulations, the traditional operating companies could incur substantial costs to clean up
properties. The traditional operating companies conduct studies to determine the extent of any
required cleanup and have recognized in their respective financial statements the costs to clean up
known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year
presented. The traditional operating companies may be liable for some or all required cleanup
costs for additional sites that may require environmental remediation. See Note 3 to the financial
statements under Environmental Matters Environmental Remediation for additional information.
Coal Combustion Byproducts
The EPA is currently evaluating whether additional regulation of coal combustion byproducts is
merited under federal solid and hazardous waste laws. The EPA has collected information from the
electric utility industry on surface impoundment safety and conducted on-site inspections at three
facilities of Alabama Power and Georgia Power as part of its evaluation. The traditional operating
companies have a routine and robust inspection program in place to ensure the integrity of their
respective coal ash surface impoundments. The EPA is expected to issue a proposal regarding
additional regulation of coal combustion byproducts in early 2010. The impact of these additional
regulations on the Company will depend on the specific provisions of the final rule and cannot be
determined at this time. However, additional regulation of coal combustion byproducts could have a
significant impact on the traditional operating companies management, beneficial use, and disposal
of such byproducts and could result in significant additional compliance costs that could affect
future unit retirement and replacement decisions and results of operations, cash flows, and
financial condition if such costs are not recovered through regulated rates.
Global Climate Issues
Federal legislative proposals that would impose mandatory requirements related to greenhouse gas
emissions, renewable energy standards, and energy efficiency standards continue to be considered in
Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by
the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009
(ACES), which would impose mandatory greenhouse gas restrictions through implementation of a cap
and trade program, a renewable energy standard, and other measures, was passed by the House of
Representatives. ACES would require reductions of greenhouse gas emissions on a national basis to
a level that is 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005
levels by 2050. In addition, ACES would provide for renewable energy standards of 6% by 2012 and
20% by 2020. Similar legislation is being considered by the Senate. The financial and operational
impact of such legislation, if enacted, will depend on a variety of factors. These factors include
the specific greenhouse gas emissions limits or renewable energy requirements, the timing of
implementation of these limits or requirements, the level of emissions allowances allocated and the
level that must be purchased, the purchase price of emissions allowances, the development and
commercial availability of technologies for renewable energy and for the reduction of emissions,
the degree to which offsets may be used for compliance, provisions for cost containment (if any),
the impact on coal and natural gas prices, and cost recovery through regulated rates. There can be
no assurance that any legislation will be enacted or as to the ultimate form of any legislation.
Additional or alternative legislation may be adopted as well.
In April 2007, the U.S. Supreme Court ruled that the EPA has authority under the Clean Air Act to
regulate greenhouse gas emissions from new motor vehicles. On December 15, 2009, the EPA published
a final determination, which became effective on January 14, 2010, that certain greenhouse gas
emissions from new motor vehicles endanger public health and welfare due to climate change. On
September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new
motor vehicles under the Clean Air Act. The EPA has stated that once this rule is effective, it
will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the
Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V
operating permit program, which both apply to power plants. As a result, the construction of new
facilities or the major modification of existing facilities could trigger the requirement for a PSD
permit and the installation of the best available control technology for carbon dioxide and other
greenhouse gases. The EPA also published a proposed rule governing how these programs would be
applied to stationary sources, including power plants, on October 27, 2009. The EPA has stated
that it expects to finalize these proposed rules in March 2010. The ultimate outcome of the
endangerment finding and these proposed rules cannot be determined at this time and will depend on
additional regulatory action and any legal challenges.
International climate change negotiations under the United Nations Framework Convention on Climate
Change also continue. A nonbinding agreement was announced during the most recent round of
negotiations in December 2009 that included a pledge from both developed and developing countries
to reduce their greenhouse gas emissions. The outcome and impact of the international negotiations
cannot be determined at this time.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Although the outcome of federal, state, or international initiatives cannot be determined at this
time, mandatory restrictions on the Companys greenhouse gas emissions or requirements relating to
renewable energy or energy efficiency on the federal or state level are likely to result in
significant additional compliance costs, including significant capital expenditures. These costs
could affect future unit retirement and replacement decisions, and could result in the retirement
of a significant number of coal-fired generating units. See Item 1 BUSINESS Rate Matters
Integrated Resource Planning for additional information. Also, additional compliance costs and
costs related to unit retirements could affect results of operations, cash flows, and financial
condition if such costs are not recovered through regulated rates. Further, higher costs that are
recovered through regulated rates could contribute to reduced demand for electricity, which could
negatively impact results of operations, cash flows, and financial condition.
In 2008, the total carbon dioxide emissions from the fossil fuel-fired electric generating units
owned by the electric utilities were approximately 142 million metric tons. The preliminary estimate of
carbon dioxide emissions from these units in 2009 is approximately 121 million metric tons. The
level of carbon dioxide emissions from year to year will be dependent on the level of generation
and mix of fuel sources, which is determined primarily by demand, the unit cost of fuel consumed,
and the availability of generating units.
The Company is actively evaluating and developing electric generating technologies with lower
greenhouse gas emissions. These include new nuclear generation, including two additional
generating units at Plant Vogtle in Georgia; proposed construction of an advanced IGCC unit with
approximately 65% carbon capture in Kemper County, Mississippi; and renewables investments,
including the construction of a biomass plant in Sacul, Texas. The Company is currently
considering additional projects and is pursuing research into the costs and viability of other
renewable technologies for the Southeast.
PSC Matters
Alabama Power
Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar
year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year
and any annual adjustment is limited to 5%. Retail rates remain unchanged when the retail return
on common equity (ROE) is projected to be between 13% and 14.5%. If Alabama Powers actual retail
ROE is above the allowed equity return range, customer refunds will be required; however, there is
no provision for additional customer billings should the actual retail ROE fall below the allowed
equity return range.
On December 1, 2009, Alabama Power made its Rate RSE submission to the Alabama PSC of projected
data for calendar year 2010. The Rate RSE increase for 2010 is 3.2%, or $152 million annually, and
was effective in January 2010. The revenue adjustment under the Rate RSE is largely attributable
to the costs associated with fossil capacity which is currently dedicated to certain long-term
wholesale contracts that expire during 2010. Retail cost of service for 2010 reflects the cost for
that portion of the year in which this capacity is no longer committed to wholesale. The
termination of these long-term wholesale contracts will result in a significant decrease in unit
power sales capacity revenues. In an Alabama PSC order dated January 5, 2010, the Alabama PSC
acknowledged that a full calendar year of costs for such capacity would be reflected in the Rate
RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the maximum
increase for 2011 cannot exceed 4.76%.
The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the
cost of placing new generating facilities in retail service and for the recovery of retail costs
associated with certificated PPAs under a Rate Certificated New Plant (Rate CNP). There was no
adjustment to Rate CNP in April 2007, 2008, or 2009. Effective April 2010, Rate CNP will be
reduced approximately $70 million annually, primarily due to the expiration on May 31, 2010 of the
PPA with Southern Power covering the capacity of Plant Harris Unit 1. Rate CNP also allows for the
recovery of Alabama Powers retail costs associated with environmental laws, regulations, or other
such mandates. The rate mechanism is based on forward-looking information and provides for the
recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to
be recovered include operations and maintenance expenses, depreciation, and a return on invested
capital.
On December 1, 2009, Alabama Power made its Rate CNP environmental submission to the Alabama PSC of
projected data for calendar year 2010. The Rate CNP environmental increase for 2010 is 4.3%, or
$195 million annually, based upon projected billings. Under the terms of the rate mechanism, the
adjustment became effective in January 2010. The Rate CNP environmental adjustment is primarily
attributable to scrubbers being placed in service during 2010 at four of Alabama Powers generating
plants. See Note 3 to the financial statements under Retail Regulatory Matters Alabama Power
Retail Rate Plans for further information.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Georgia Power
In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate
Plan, Georgia Powers earnings are evaluated against a retail ROE range of 10.25% to 12.25%.
Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for
cost recovery of transmission, distribution, generation, and other investments, as well as
increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery
of costs related to environmental projects mandated by state and federal regulations. The ECCR
tariff increased rates by approximately $222 million effective January 1, 2008.
In connection with the 2007 Retail Rate Plan, Georgia Power agreed that it would not file for a
general base rate increase during this period unless its projected retail ROE falls below 10.25%.
The economic recession has significantly reduced Georgia Powers revenues upon which retail rates
were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce
expenses, Georgia Powers projected retail ROE for both 2009 and 2010 was below 10.25%. However,
in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June
29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would
allow Georgia Power to amortize up to $324 million of its regulatory liability related to other
cost of removal obligations.
On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the
accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory
liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail
ROE. For the year ended December 31, 2009, Georgia Power amortized $41 million of the regulatory
liability. In addition, Georgia Power may amortize up to two-thirds of the regulatory liability
($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE.
Georgia Power is required to file a general rate case by July 1, 2010, in response to which the
Georgia PSC would be expected to determine whether the 2007 Retail Rate Plan should be continued,
modified, or discontinued. See Note 3 to the financial statements under Retail Regulatory Matters
Georgia Power Retail Rate Plans for additional information.
Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by
their respective state PSCs. In previous years, the traditional operating companies experienced
higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have
resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and
Gulf Power of approximately $667 million at December 31, 2009. During the third quarter 2009,
Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of
December 31, 2009, have a total over recovered fuel balance of $229 million. The total under
recovered fuel costs included in the balance sheets of the traditional operating companies at
December 31, 2008 was $1.2 billion. The traditional operating companies continuously monitor the
under or over recovered fuel cost balances.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in
actual recoverable costs and amounts billed in current regulated rates. Accordingly, changing the
billing factor has no significant effect on the Companys revenues or net income, but does impact
annual cash flow. See Note 1 to the financial statements under Revenues and Note 3 to the
financial statements under Retail Regulatory Matters Alabama Power Fuel Cost Recovery and
Retail Regulatory Matters Georgia Power Fuel Cost Recovery for additional information.
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of
2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and
multiple renewable energy incentives, which could have a significant impact on the future cash flow
and net income of Southern Company. Southern Companys cash flow reduction to 2009 tax payments as
a result of the bonus depreciation provisions of the ARRA was approximately $250 million. On
December 8, 2009, President Obama announced proposals to accelerate job growth that include an
extension of the bonus depreciation provision for the ARRA for 2010, which could have a significant
impact on the future cash flow and net income of Southern Company.
On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165
million had been granted under the ARRA grant application for transmission and distribution
automation and modernization projects pending final negotiations. Southern Company continues to
assess the other financial implications of the ARRA.
The U.S. House of Representatives and the U.S. Senate have passed separate bills related to
healthcare reform. Both bills include a provision that would make Medicare Part D subsidy
reimbursements taxable. If enacted into law, this provision could have a
C-20
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
significant negative impact on Southern Companys net income. See Note 2 to the financial
statements under Other Postretirement Benefits for additional information.
The ultimate impact of these matters cannot be determined at this time.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Powers 2005 through 2008 income tax filings for the State of Georgia include state income
tax credits for increased activity through Georgia ports. Georgia Power has also filed similar
claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to
these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County
to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has
been recorded related to these credits. See Note 5 to the financial statements under Unrecognized
Tax Benefits for additional information. If Georgia Power prevails, these claims could have a
significant, and possibly material, positive effect on Southern Companys net income. If Georgia
Power is not successful, payment of the related state tax could have a significant, and possibly
material, negative effect on Southern Companys cash flow. The ultimate outcome of this matter
cannot now be determined.
Internal Revenue Code Section 199 Domestic Production Deduction
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable
to U.S. production activities as defined in Section 199 of the Internal Revenue Code. The
deduction is equal to a stated percentage of qualified production activities net income. The
percentage is phased in over the years 2005 through 2010 with a 3% rate applicable to the years
2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a 9% rate thereafter. See
Note 5 to the financial statements under Effective Tax Rate for additional information.
Construction Program
The subsidiary companies of Southern Company are engaged in continuous construction programs to
accommodate existing and estimated future loads on their respective systems. Southern Company
intends to continue its strategy of developing and constructing new generating facilities,
including units at Southern Power, proposed new nuclear units, and a proposed IGCC facility, as
well as adding environmental control equipment and expanding the transmission and distribution
systems. For the traditional operating companies, major generation construction projects are
subject to state PSC approvals in order to be included in retail rates. While Southern Power
generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted
capacity could negatively affect future earnings. See Note 7 to the financial statements under
Construction Program for estimated construction expenditures for the next three years. In
addition, see Note 3 to the financial statements under Retail Regulatory Matters Georgia Power
Nuclear Construction and Retail Regulatory Matters Integrated Coal Gasification Combined Cycle
for additional information.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated,
regulatory matters, and certain tax-related issues that could affect future earnings. In addition,
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in
the ordinary course of business. The business activities of Southern 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 opacity and air and water quality standards, has
increased generally throughout the United States. In particular, personal injury and other claims
for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for
injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have
become more frequent. The ultimate outcome of such pending or potential litigation against
Southern Company and its subsidiaries cannot be predicted at this time; however, for current
proceedings not specifically reported herein, management does not anticipate that the liabilities,
if any, arising from such current proceedings would have a material adverse effect on Southern
Companys financial statements. See Note 3 to the financial statements for information regarding
material issues.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting policies are described
in Note 1 to the financial statements. In the application of these policies, certain estimates are
made that may have a material impact on Southern 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 discussed the
development and selection of the critical accounting policies and estimates described below with
the Audit Committee of Southern Companys Board of Directors.
Electric Utility Regulation
Southern Companys traditional operating companies, which comprised approximately 97% of Southern
Companys total operating revenues for 2009, are subject to retail regulation by their respective
state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the
traditional operating companies are permitted to charge customers based on allowable costs. As a
result, the traditional operating companies apply accounting standards which require the financial
statements to reflect the effects of rate regulation. Through the ratemaking process, the
regulators may require the inclusion of costs or revenues in periods different than when they would
be recognized by a non-regulated company. This treatment may result in the deferral of expenses
and the recording of related regulatory assets based on anticipated future recovery through rates
or the deferral of gains or creation of liabilities and the recording of related regulatory
liabilities. The application of the accounting standards has a further effect on the 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,
nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on
the Companys results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities
have been recorded. Management reviews the ultimate recoverability of these regulatory assets and
liabilities based on applicable regulatory guidelines and accounting principles generally accepted
in the United States. However, adverse legislative, judicial, or regulatory actions could
materially impact the amounts of such regulatory assets and liabilities and could adversely impact
the Companys financial statements.
Contingent Obligations
Southern Company and its subsidiaries are subject to a number of federal and state laws and
regulations, as well as other factors and conditions that potentially subject them to
environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and
Note 3 to the financial statements for more information regarding certain of these contingencies.
Southern Company periodically evaluates its exposure to such risks and, in accordance with GAAP,
records reserves for those matters where a non-tax-related loss is considered probable and
reasonably estimable and records a tax asset or liability if it is more likely than not that a tax
position will be sustained. The adequacy of reserves can be significantly affected by external
events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could
materially affect Southern Companys financial statements.
These events or conditions include the following:
|
|
Changes in existing state or federal regulation by governmental authorities having
jurisdiction over air quality, water quality, coal combustion byproducts, including coal ash,
control of toxic substances, hazardous and solid wastes, and other environmental matters. |
|
|
Changes in existing income tax regulations or changes in IRS or state revenue department
interpretations of existing regulations. |
|
|
Identification of additional sites that require environmental remediation or the filing of
other complaints in which Southern Company or its subsidiaries may be asserted to be a
potentially responsible party. |
|
|
Identification and evaluation of other potential lawsuits or complaints in which Southern
Company or its subsidiaries may be named as a defendant. |
|
|
Resolution or progression of new or existing matters through the legislative process, the
court systems, the IRS, state revenue departments, the FERC, or the EPA. |
C-22
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to
customers. However, the determination of KWH sales to individual customers is based on the reading
of their meters, which is performed on a systematic basis throughout the month. At the end of each
month, amounts of electricity delivered to customers, but not yet metered and billed, are
estimated. Components of the unbilled revenue estimates include total KWH territorial supply,
total KWH billed, estimated total electricity lost in delivery, and customer usage. These
components can fluctuate as a result of a number of factors including weather, generation patterns,
and power delivery volume and other operational constraints. These factors can be unpredictable
and can vary from historical trends. As a result, the overall estimate of unbilled revenues could
be significantly affected, which could have a material impact on the Companys results of
operations.
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, health care cost trend rates,
expected long-term return on plan assets, mortality rates, expected salary and wage increases, and
other factors. Components of pension and other postretirement benefits expense include interest
and service cost on the pension and other postretirement benefit plans, expected return on plan
assets and amortization of certain unrecognized costs and obligations. Actual results that differ
from the assumptions utilized are accumulated and amortized over future periods and, therefore,
generally affect recognized expense and the recorded obligation in future periods. While the
Company believes that the assumptions used are appropriate, differences in actual experience or
significant changes in assumptions would affect its pension and other postretirement benefits costs
and obligations.
Key elements in determining Southern 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
considers external actuarial advice.
Southern Company determines the long-term return on plan assets by applying the long-term rate of
expected returns on various asset classes to Southern Companys target asset allocation. Southern
Company discounts the future cash flows related to its postretirement benefit plans using a
single-point discount rate developed from the weighted average of market-observed yields for high
quality fixed income securities with maturities that correspond to expected benefit payments.
The following table illustrates the sensitivity to changes in Southern Companys long-term
assumptions with respect to the expected long-term rate of return on plan assets and the assumed
discount rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/(Decrease) in |
|
|
|
|
Increase/(Decrease) in |
|
Projected Obligation for |
|
|
Increase/(Decrease) in |
|
Projected Obligation for |
|
Other Postretirement |
|
|
Total Benefit Expense |
|
Pension Plan |
|
Benefit Plans |
Change in Assumption |
|
for 2010 |
|
at December 31, 2009 |
|
at December 31, 2009 |
|
|
|
(in millions) |
25 basis point change in
discount rate |
|
$11/$(8) |
|
$226/$(214) |
|
$53/$(51) |
25 basis point change in
salary assumption |
|
$9/$(8) |
|
$58/$(55) |
|
N/M |
25 basis point change in
long-term return on plan assets |
|
$19/$(19) |
|
N/M |
|
N/M |
|
N/M Not meaningful
C-23
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
New Accounting Standards
Variable Interest Entities
In June 2009, the Financial Accounting Standards Board issued new guidance on the consolidation of
variable interest entities, which replaces the quantitative-based risks and rewards calculation for
determining whether an enterprise is the primary beneficiary in a variable interest entity with an
approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is
the primary beneficiary of a variable interest entity, and requires additional disclosures about an
enterprises involvement in variable interest entities. Southern Company adopted this new guidance
effective January 1, 2010, with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Companys financial condition remained stable at December 31, 2009. Throughout the
turmoil in the financial markets, Southern Company has maintained adequate access to capital
without drawing on any of its committed bank credit arrangements used to support its commercial
paper programs and variable rate pollution control revenue bonds. Southern Company intends to
continue to monitor its access to short-term and long-term capital markets as well as its bank
credit arrangements to meet future capital and liquidity needs. Market rates for committed credit
have increased, and Southern Company and its subsidiaries have been and expect to continue to be
subject to higher costs as existing facilities are replaced or renewed. Total committed credit
fees for Southern Company and its subsidiaries currently average less than 1/2 of 1% per year. See
Sources of Capital and Financing Activities herein for additional information.
Southern Companys investments in pension and nuclear decommissioning trust funds remained stable
in value as of December 31, 2009. Southern Company expects that the earliest that cash may have to
be contributed to the pension trust fund is 2012 and such contribution could be significant;
however, projections of the amount vary significantly depending on key variables including future
trust fund performance and cannot be determined at this time. Southern Company does not expect any
changes to funding obligations to the nuclear decommissioning trusts prior to 2011.
Net cash
provided from operating activities in 2009 totaled $3.3 billion,
a decrease of $201
million from the corresponding period in 2008. Significant changes in operating cash flow for 2009
as compared to the corresponding period in 2008 include a reduction to net income as previously
discussed, increased levels of coal inventory, and increased cash outflows for tax payments. These
uses of funds were partially offset by increased cash inflows as a result of higher fuel cost
recovery rates included in customer billings. Net cash provided from operating activities in 2008
totaled $3.5 billion, an increase of $30 million as compared to 2007. Significant changes in
operating cash flow for 2008 included a $264 million increase in the use of funds for fossil fuel
inventory as compared to the corresponding period in 2007. This use of funds was offset by an
increase in cash of $312 million in accrued taxes primarily due to a difference between the periods
in payments for federal taxes and property taxes. Net cash provided from operating activities in
2007 totaled $3.4 billion, an increase of $583 million as compared to the corresponding period in
2006. The increase was primarily due to an increase in net income as previously discussed, an
increase in cash collections from previously deferred fuel and storm damage costs, and a reduction
in cash outflows compared to the previous year in fossil fuel inventory.
Net cash used for investing activities in 2009 totaled $4.3 billion primarily due to property
additions to utility plant of $4.7 billion, partially offset by approximately $340 million in cash
received from the early termination of two leveraged lease investments. Net cash used for
investing activities in 2008 totaled $4.1 billion primarily due to property additions to utility
plant of $4.0 billion. In 2007, net cash used for investing activities was $3.7 billion primarily
due to property additions to utility plant of $3.5 billion.
Net cash provided from financing activities totaled $1.3 billion in 2009 primarily due to the
issuance of new long-term debt and common stock issuances, partially offset by cash outflows for
repayments of long-term debt and dividend payments. Net cash provided from financing activities
totaled $878 million in 2008 primarily due to long-term debt issuances. Net cash provided from
financing activities totaled $309 million in 2007 primarily due to replacement of short-term debt
with longer term financing and cash raised from common stock programs.
Significant
balance sheet changes in 2009 include an increase of $3.4 billion in total property,
plant, and equipment for the installation of equipment to comply with environmental standards and
construction of generation, transmission, and distribution facilities. Other
C-24
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
significant changes include an increase in long-term debt, excluding amounts due within one year,
of $1.3 billion used primarily for construction expenditures and general corporate purposes and
$1.6 billion of additional equity.
At the end of 2009, the closing price of Southern Companys common stock was $33.32 per share,
compared with book value of $18.15 per share. The market-to-book value ratio was 184% at the end
of 2009, compared with 217% at year-end 2008.
Southern Company, each of the traditional operating companies, and Southern Power have received
investment grade credit ratings from the major rating agencies with respect to debt, preferred
securities, preferred stock, and/or preference stock. Southern Company Services, Inc. has an
investment grade corporate credit rating. See Credit Rating Risk herein for additional
information.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external
security issuances. Equity capital can be provided from any combination of the Companys stock
plans, private placements, or public offerings. The amount and timing of additional equity capital
to be raised in 2010, as well as in subsequent years, will be contingent on Southern Companys
investment opportunities.
The traditional operating companies and Southern Power plan to obtain the funds required for
construction and other purposes from sources similar to those used in the past, which were
primarily from operating cash flows, security issuances, term loans, short-term borrowings, and
equity contributions from Southern Company. However, the type and timing of any financings, if
needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In
addition, on February 16, 2010, the U.S. Department of Energy (DOE) offered Georgia Power a
conditional commitment for federal loan guarantees that would apply to future Georgia Power
borrowings related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units
3 and 4). Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured
by a first priority lien on Georgia Powers 45.7% undivided ownership interest in Plant Vogtle
Units 3 and 4. Total guaranteed borrowings would not exceed 70% of eligible project costs, or
approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Georgia
Power has 90 days to accept the conditional commitment, including obtaining any necessary
regulatory approvals. Georgia Power will work with the DOE to finalize loan guarantees. Final
approval and issuance of loan guarantees by the DOE are subject to receipt of the combined
construction and operating license for Plant Vogtle Units 3 and 4 from the Nuclear Regulatory
Commission (NRC), negotiation of definitive agreements, completion of due diligence by the DOE,
receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be
no assurance that the DOE will issue loan guarantees for Georgia Power.
The issuance of securities by the traditional operating companies is generally subject to the
approval of the applicable state PSC. The issuance of all securities by Mississippi Power and
Southern Power and short-term securities by Georgia Power is generally subject to regulatory
approval by the FERC. Additionally, with respect to the public offering of securities, Southern
Company and certain of its subsidiaries file registration statements with the Securities and
Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of
securities authorized by the appropriate regulatory authorities, as well as the amounts, if any,
registered under the 1933 Act, are continuously monitored and appropriate filings are made to
ensure flexibility in the capital markets.
Southern Company, each traditional operating company, and Southern Power obtain financing
separately without credit support from any affiliate. See Note 6 to the financial statements under
Bank Credit Arrangements for additional information. The Southern Company system does not
maintain a centralized cash or money pool. Therefore, funds of each company are not commingled
with funds of any other company.
Southern Companys current liabilities frequently exceed current assets because of the continued
use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of
long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial
cash flow from operating activities and access to capital markets, including commercial paper
programs (which are backed by bank credit facilities).
At December 31, 2009, Southern Company and its subsidiaries had approximately $690 million of cash
and cash equivalents and $4.8 billion of unused credit arrangements with banks, of which $1.5
billion expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately
$81 million of the credit facilities expiring in 2010 allow for the execution of term loans for an
additional two-year period, and $517 million allow for the execution of one-year term loans. Most
of these arrangements contain covenants that limit debt levels and typically contain cross default
provisions that are restricted only to the indebtedness of the individual company. Southern
Company and its subsidiaries are currently in compliance with all such covenants. A portion of the
unused credit with banks is allocated to provide liquidity support to the traditional operating
companies variable rate pollution control
C-25
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity
support as of December 31, 2009 was approximately $1.6 billion. Subsequent to December 31, 2009,
two remarketings of pollution control revenue bonds increased that amount to $1.8 billion. See
Note 6 to the financial statements under Bank Credit Arrangements for additional information.
Financing Activities
During 2009, Southern Company issued $350 million of Series 2009A 4.15% Senior Notes due May 15,
2014 and $300 million of Series 2009B Floating Rate Senior Notes due October 21, 2011, and its
subsidiaries issued $1.8 billion of senior notes and incurred obligations of $625 million related
to the issuance of pollution control revenue bonds. A portion of the proceeds of the newly issued
pollution control revenue bonds were used to retire $327 million of outstanding pollution control
revenue bonds. Southern Company also issued 22.6 million shares of common stock for $673 million
through the Southern Investment Plan and employee and director stock plans. In addition, Southern
Company issued 19.9 million shares of common stock through at-the-market issuances pursuant to
sales agency agreements related to Southern Companys continuous equity offering program and
received cash proceeds of $613 million, net of $6 million in fees and commissions. The proceeds
were primarily used to redeem or repay at maturity $1.2 billion of long-term debt, to fund ongoing
construction projects, to repay short-term and long-term indebtedness, and for general corporate
purposes.
Also during 2009, Georgia Power and Gulf Power entered into forward starting interest rate swaps to
mitigate exposure to interest rate changes related to anticipated debt issuances. The notional
amounts of the swaps totaled $200 million and $100 million, respectively. Georgia Power had net
realized losses of $19 million upon termination of $300 million of interest rate hedges during
2009. The effective portion of these losses has been deferred in other comprehensive income and is
being amortized to interest expense over the life of the original interest rate hedge.
In 2009, Southern Company used a portion of the cash received from the early termination of two
leveraged lease investments to extinguish $253 million of debt which included all debt related to
these leveraged lease investments and to pay make-whole redemption premiums of $17 million
associated with such debt.
In addition to any financings that may be necessary to meet capital requirements and contractual
obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a
program to retire higher-cost securities and replace these obligations with lower-cost capital if
market conditions permit.
Off-Balance Sheet Financing Arrangements
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle
generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating
facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are
unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease
agreement with Mississippi Power. Juniper has also entered into leases with other parties
unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of
Junipers assets. Mississippi Power is not required to consolidate the leased assets and related
liabilities, and the lease with Juniper is considered an operating lease. The lease also provides
for a residual value guarantee, approximately 73% of the acquisition cost, by Mississippi Power
that is due upon termination of the lease in the event that Mississippi Power does not renew the
lease or purchase the assets and that the fair market value is less than the unamortized cost of
the assets. In April 2010, 18 months prior to the end of the initial lease term, Mississippi Power
may elect to renew for 10 years. See Note 7 to the financial statements under Operating Leases
for additional information.
Credit Rating Risk
Southern Company does not have any credit arrangements that would require material changes in
payment schedules or terminations as a result of a credit rating downgrade. There are certain
contracts that could require collateral, but not accelerated payment, in the event of a credit
rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These
contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and
storage, emissions allowances, energy price risk management, and construction of new generation
facilities. At December 31, 2009, the maximum potential collateral requirements under these
contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating
were approximately $467 million. At December 31, 2009, the maximum potential collateral
requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.3
billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit,
or cash. Additionally, any credit rating downgrade could impact Southern Companys ability to
access capital markets, particularly the short-term debt market.
C-26
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
On September 2, 2009, Moodys Investors Service (Moodys) affirmed the credit ratings of Southern
Companys senior unsecured notes and commercial paper of A3/P-1, respectively, and revised the
rating outlook for Southern Company to negative. On September 4, 2009, Fitch Ratings, Inc.
affirmed Southern Companys long-term and commercial paper credit ratings of A/F1, respectively,
and maintained its stable rating outlook. On October 6, 2009, Standard and Poors Rating Services,
a division of The McGraw-Hill Companies, Inc. (S&P) affirmed the credit ratings of Southern
Companys senior unsecured notes and commercial paper of A-/A-1, respectively, and maintained a
stable rating outlook.
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk.
To manage the volatility attributable to these exposures, the Company nets the exposures, where
possible, to take advantage of natural offsets and enters into various derivative transactions for
the remaining exposures pursuant to the Companys policies in areas such as counterparty exposure
and risk management practices. Company policy is that derivatives are to be used primarily for
hedging purposes and mandates strict adherence to all applicable risk management policies.
Derivative positions are monitored using techniques including, but not limited to, market
valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, the Company enters into forward starting
interest rate swaps and other derivatives that have been designated as hedges. Derivatives
outstanding at December 31, 2009 have a notional amount of $976 million and are related to
anticipated debt issuances and various floating rate obligations over the next year. The weighted
average interest rate on $2.7 billion of long-term variable interest rate exposure that has not
been hedged at January 1, 2010 was 0.76%. If Southern Company sustained a 100 basis point change
in interest rates for all unhedged variable rate long-term debt, the change would affect annualized
interest expense by approximately $27 million at January 1, 2010. For further information, see
Note 1 to the financial statements under Financial Instruments and Note 11 to the financial
statements.
Due to cost-based rate regulation, the traditional operating companies continue to have limited
exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity.
In addition, Southern 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 sales of uncontracted
generating capacity. To mitigate residual risks relative to movements in electricity prices, the
traditional operating companies enter into physical fixed-price contracts for the purchase and sale
of electricity through the wholesale electricity market and, to a lesser extent, into financial
hedge contracts for natural gas purchases. The traditional operating companies continue to manage
fuel-hedging programs implemented per the guidelines of their respective state PSCs.
The changes in fair value of energy-related derivative contracts were as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Changes |
|
Changes |
|
|
|
Fair Value |
|
|
|
(in millions) |
Contracts outstanding at the beginning of the period, assets
(liabilities), net |
|
$ |
(285 |
) |
|
$ |
4 |
|
Contracts realized or settled |
|
|
367 |
|
|
|
(150 |
) |
Current period changes(a) |
|
|
(260 |
) |
|
|
(139 |
) |
|
Contracts outstanding at the end of the period, assets (liabilities), net |
|
$ |
(178 |
) |
|
$ |
(285 |
) |
|
(a) |
|
Current period changes also include the changes in fair value of new
contracts entered into during the period, if any. |
The change in the fair value positions of the energy-related derivative contracts for the year
ended December 31, 2009 was an increase of $107 million, substantially all of which is due to
natural gas positions. The change is attributable to both the volume of million British thermal
units (mmBtu) and prices of natural gas. At December 31, 2009, Southern Company had a net hedge
volume of 154 million mmBtu (includes location basis of 2 million mmBtu) with a weighted average
contract cost approximately $1.17 per mmBtu above market prices, compared to 149 million mmBtu
(includes location basis of 2 million mmBtu) at December 31, 2008 with a weighted average contract
cost approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedges are
recorded through the traditional operating companies fuel cost recovery clauses.
C-27
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
At December 31, the net fair value of energy-related derivative contracts by hedge designation was
reflected in the financial statements as assets/(liabilities) as follows:
|
|
|
|
|
|
|
|
|
Asset (Liability) Derivatives |
|
2009 |
|
|
2008 |
|
|
|
|
(in millions) |
|
Regulatory hedges |
|
$ |
(175 |
) |
|
$ |
(288 |
) |
Cash flow hedges |
|
|
(2 |
) |
|
|
(1 |
) |
Not designated |
|
|
(1 |
) |
|
|
4 |
|
|
Total fair value |
|
$ |
(178 |
) |
|
$ |
(285 |
) |
|
Energy-related derivative contracts which are designated as regulatory hedges relate to the
traditional operating companies fuel hedging programs, where gains and losses are initially
recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense
as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related
derivatives designated as cash flow hedges are mainly used by Southern Power to hedge anticipated
purchases and sales and are initially deferred in other comprehensive income before being
recognized in income in the same period as the hedged transaction. Gains and losses on
energy-related derivative contracts that are not designated or fail to qualify as hedges are
recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in the statements of income for the years
ended December 31, 2009, 2008, and 2007 for energy-related derivative contracts that are not hedges
were $(5) million, $1 million, and $3 million, respectively.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy
in which they fall at December 31, 2009 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
Fair Value Measurements |
|
|
Total |
|
Maturity |
|
|
Fair Value |
|
Year 1 |
|
Years 2&3 |
|
Years 4&5 |
|
|
|
(in millions) |
Level 1 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Level 2 |
|
|
(178 |
) |
|
|
(113 |
) |
|
|
(65 |
) |
|
|
|
|
Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at end of period |
|
$ |
(178 |
) |
|
$ |
(113 |
) |
|
$ |
(65 |
) |
|
$ |
|
|
|
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued
using prices which are actively quoted, and thus fall into Level 2. See Note 10 to the financial
statements for further discussion on fair value measurement.
Southern Company is exposed to market price risk in the event of nonperformance by counterparties
to energy-related and interest rate derivative contracts. Southern Company only enters into
agreements and material transactions with counterparties that have investment grade credit ratings
by 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.
During 2007, Southern Company had derivatives in place to reduce its exposure to a phase-out of
certain income tax credits related to synthetic fuel production in 2007. In accordance with
Internal Revenue Code Section 45K, these tax credits were subject to limitation as the annual
average price of oil increased. Because these transactions were not designated as hedges, the
gains and losses were recognized in the statements of income as incurred. These derivatives
settled on January 1, 2008 and thus there was no income statement impact for the years ended
December 31, 2008 and 2009. For 2007, the unrealized fair value gain recognized in other income to
mark the transactions to market was $27 million.
C-28
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Capital Requirements and Contractual Obligations
The construction program of Southern Company is currently estimated to be $4.9 billion for 2010,
$5.3 billion for 2011, and $6.2 billion for 2012. These estimates include costs for new generation
construction. Environmental expenditures included in these estimated amounts are $545 million,
$721 million, and $1.2 billion for 2010, 2011, and 2012, respectively. The construction programs
are subject to periodic review and revision, and actual construction costs may vary from these
estimates because of numerous factors. These factors include: changes in business conditions;
changes in load projections; changes in environmental statutes and regulations; changes in nuclear
plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals;
changes in legislation; the cost and efficiency of construction labor, equipment, and materials;
project scope and design changes; and the cost of capital. In addition, there can be no assurance
that costs related to capital expenditures will be fully recovered. See Note 3 to the financial
statements under Retail Regulatory Matters Georgia Power Nuclear Construction and Retail
Regulatory Matters Integrated Coal Gasification Combined Cycle and Note 7 to the financial
statements under Construction Program for additional information.
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for
nuclear decommissioning costs; however, Alabama Power currently has no additional funding
requirements. For additional information, see Note 1 to the financial statements under Nuclear
Decommissioning.
In addition, as discussed in Note 2 to the financial statements, Southern Company provides
postretirement benefits to substantially all employees and funds trusts to the extent required by
the traditional operating companies respective regulatory commissions.
Other funding requirements related to obligations associated with scheduled maturities of long-term
debt, as well as the related interest, derivative obligations, preferred and preference stock
dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, 7, and 11 to the
financial statements for additional information.
C-29
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011- |
|
2013- |
|
After |
|
Uncertain |
|
|
|
|
2010 |
|
2012 |
|
2014 |
|
2014 |
|
Timing(d) |
|
Total |
|
|
|
(in millions) |
Long-term debt(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
1,092 |
|
|
$ |
2,880 |
|
|
$ |
1,361 |
|
|
$ |
13,836 |
|
|
$ |
|
|
|
$ |
19,169 |
|
Interest |
|
|
894 |
|
|
|
1,732 |
|
|
|
1,455 |
|
|
|
11,905 |
|
|
|
|
|
|
|
15,986 |
|
Preferred and preference stock dividends(b) |
|
|
65 |
|
|
|
130 |
|
|
|
130 |
|
|
|
|
|
|
|
|
|
|
|
325 |
|
Other derivative obligations(c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related |
|
|
119 |
|
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
185 |
|
Operating leases |
|
|
144 |
|
|
|
192 |
|
|
|
99 |
|
|
|
124 |
|
|
|
|
|
|
|
559 |
|
Capital leases |
|
|
21 |
|
|
|
26 |
|
|
|
11 |
|
|
|
40 |
|
|
|
|
|
|
|
98 |
|
Unrecognized tax benefits and interest(d) |
|
|
184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
220 |
|
Purchase commitments(e) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital(f) |
|
|
4,665 |
|
|
|
11,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,825 |
|
Limestone(g) |
|
|
37 |
|
|
|
72 |
|
|
|
76 |
|
|
|
110 |
|
|
|
|
|
|
|
295 |
|
Coal |
|
|
4,490 |
|
|
|
4,707 |
|
|
|
1,913 |
|
|
|
2,508 |
|
|
|
|
|
|
|
13,618 |
|
Nuclear fuel |
|
|
271 |
|
|
|
323 |
|
|
|
231 |
|
|
|
297 |
|
|
|
|
|
|
|
1,122 |
|
Natural gas(h) |
|
|
1,349 |
|
|
|
2,192 |
|
|
|
1,504 |
|
|
|
4,153 |
|
|
|
|
|
|
|
9,198 |
|
Biomass fuel(i) |
|
|
|
|
|
|
17 |
|
|
|
35 |
|
|
|
128 |
|
|
|
|
|
|
|
180 |
|
Purchased power |
|
|
253 |
|
|
|
524 |
|
|
|
502 |
|
|
|
2,742 |
|
|
|
|
|
|
|
4,021 |
|
Long-term service agreements(j) |
|
|
103 |
|
|
|
251 |
|
|
|
263 |
|
|
|
1,738 |
|
|
|
|
|
|
|
2,355 |
|
Trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning(k) |
|
|
3 |
|
|
|
7 |
|
|
|
7 |
|
|
|
53 |
|
|
|
|
|
|
|
70 |
|
Postretirement benefits(l) |
|
|
43 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119 |
|
|
Total |
|
$ |
13,733 |
|
|
$ |
24,355 |
|
|
$ |
7,587 |
|
|
$ |
37,634 |
|
|
$ |
36 |
|
|
$ |
83,345 |
|
|
|
|
|
(a) |
|
All amounts are reflected based on final maturity dates. Southern Company and its
subsidiaries plan to continue to retire higher-cost securities and replace these obligations
with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2010, as reflected in the statements of
capitalization. Fixed rates include, where applicable, the effects of interest rate
derivatives employed to manage interest rate risk. Excludes capital lease amounts (shown
separately). |
|
(b) |
|
Preferred and preference stock do not mature; therefore, amounts are provided for the next
five years only. |
|
(c) |
|
For additional information, see Notes 1 and 11 to the financial statements. |
|
(d) |
|
The timing related to the realization of $36 million in unrecognized tax benefits and
interest payments in individual years beyond 12 months cannot be reasonably and reliably
estimated due to uncertainties in the timing of the effective settlement of tax positions.
See Notes 3 and 5 to the financial statements for additional information. |
|
(e) |
|
Southern Company generally does not enter into non-cancelable commitments for other
operations and maintenance expenditures. Total other operations and maintenance expenses for
2009, 2008, and 2007 were $3.5 billion, $3.8 billion, and $3.7 billion, respectively. |
|
(f) |
|
Southern Company forecasts capital expenditures over a three-year period. Amounts represent
current estimates of total expenditures excluding those amounts related to contractual
purchase commitments for nuclear fuel. At December 31, 2009, significant purchase commitments
were outstanding in connection with the construction program. |
|
(g) |
|
As part of Southern Companys program to reduce sulfur dioxide emissions from its coal
plants, the traditional operating companies have entered into various long-term commitments
for the procurement of limestone to be used in flue gas desulfurization equipment. |
|
(h) |
|
Natural gas purchase commitments are based on various indices at the time of delivery.
Amounts reflected have been estimated based on the New York Mercantile Exchange future prices
at December 31, 2009. |
|
(i) |
|
Biomass fuel commitments are based on minimum committed tonnage of wood waste purchases. |
|
(j) |
|
Long-term service agreements include price escalation based on inflation indices. |
|
(k) |
|
Projections of nuclear decommissioning trust contributions are based on the 2007 Retail
Rate Plan and are subject to change in Georgia Powers 2010 retail rate case. |
|
(l) |
|
Southern Company forecasts postretirement trust contributions over a three-year period.
Southern Company expects that the earliest that cash may have to be contributed to the pension
trust fund is 2012 and such contribution could be significant; however, projections of the amount
vary significantly depending on key variables including future trust fund performance and cannot be
determined at this time. Therefore, no amounts related to the pension trust fund are included in
the table. See Note 2 to the financial statements for additional information related to the
pension and postretirement plans, including estimated benefit payments. Certain benefit payments
will be made through the related trusts. Other benefit payments will be made from Southern
Companys corporate assets. |
C-30
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Companys 2009 Annual Report contains forward-looking statements. Forward-looking
statements include, among other things, statements concerning the strategic goals for the wholesale
business, retail sales, customer growth, storm damage cost recovery and repairs, fuel cost recovery
and other rate actions, environmental regulations and expenditures, earnings, dividend payout
ratios, access to sources of capital, projections for postretirement benefit and nuclear
decommissioning trust contributions, financing activities, start and completion of construction
projects, plans and estimated costs for new generation resources, impacts of adoption of new
accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project,
impact of the American Recovery
and Reinvestment Act of 2009, impact of healthcare legislation, if any, estimated sales and
purchases under new power sale and purchase agreements, and estimated construction and other
expenditures. In some cases, forward-looking statements can be identified by terminology such as
may, will, could, should, expects, plans, anticipates, believes, estimates,
projects, predicts, potential, or continue or the negative of these terms or other similar
terminology. There are various factors that could cause actual results to differ materially from
those suggested by the forward-looking statements; accordingly, there can be no assurance that such
indicated results will be realized. These factors include:
|
|
the impact of recent and future federal and state regulatory change, including legislative
and regulatory initiatives regarding deregulation and restructuring of the electric utility
industry, implementation of the Energy Policy Act of 2005, environmental laws including
regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot,
particulate matter, or coal combustion byproducts and other substances, and also changes in
tax and other laws and regulations to which Southern Company and its subsidiaries are subject,
as well as changes in application of existing laws and regulations; |
|
|
|
current and future litigation, regulatory investigations, proceedings, or inquiries,
including the pending EPA civil actions against certain Southern Company subsidiaries, FERC
matters, IRS audits, and Mirant matters; |
|
|
|
the effects, extent, and timing of the entry of additional competition in the markets in
which Southern Companys subsidiaries operate; |
|
|
|
variations in demand for electricity, including those relating to weather, the general
economy and recovery from the recent recession, population and business growth (and declines),
and the effects of energy conservation measures; |
|
|
|
available sources and costs of fuels; |
|
|
|
effects of inflation; |
|
|
|
ability to control costs and avoid cost overruns during the development and construction of facilities; |
|
|
|
investment performance of Southern Companys employee benefit plans and nuclear decommissioning trusts; |
|
|
|
advances in technology; |
|
|
|
state and federal rate regulations and the impact of pending and future rate cases and
negotiations, including rate actions relating to fuel and other cost recovery mechanisms; |
|
|
|
regulatory approvals and actions related to the potential Plant Vogtle expansion,
including Georgia PSC and NRC approvals and potential DOE loan guarantees; |
|
|
|
the performance of projects undertaken by the non-utility businesses and the success of
efforts to invest in and develop new opportunities; |
|
|
|
internal restructuring or other restructuring options that may be pursued; |
|
|
|
potential business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial to Southern Company or its
subsidiaries; |
|
|
|
the ability of counterparties of Southern Company and its subsidiaries to make payments as
and when due and to perform as required; |
|
|
|
the ability to obtain new short- and long-term contracts with wholesale customers; |
|
|
|
the direct or indirect effect on Southern Companys business resulting from terrorist
incidents and the threat of terrorist incidents; |
|
|
|
interest rate fluctuations and financial market conditions and the results of financing
efforts, including Southern Companys and its subsidiaries credit ratings; |
|
|
|
the ability of Southern Company and its subsidiaries to obtain additional generating capacity
at competitive prices; |
|
|
|
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts,
pandemic health events such as influenzas, or other similar occurrences; |
|
|
|
the direct or indirect effects on Southern Companys business resulting from incidents
affecting the U.S. electric grid or operation of generating resources; |
|
|
|
the effect of accounting pronouncements issued periodically by standard setting bodies; and |
|
|
|
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed
by the Company from time to time with the SEC. |
Southern Company expressly disclaims any obligation to update any forward-looking statements.
C-31
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Retail revenues |
|
$ |
13,307 |
|
|
$ |
14,055 |
|
|
$ |
12,639 |
|
Wholesale revenues |
|
|
1,802 |
|
|
|
2,400 |
|
|
|
1,988 |
|
Other electric revenues |
|
|
533 |
|
|
|
545 |
|
|
|
513 |
|
Other revenues |
|
|
101 |
|
|
|
127 |
|
|
|
213 |
|
|
Total operating revenues |
|
|
15,743 |
|
|
|
17,127 |
|
|
|
15,353 |
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
|
5,952 |
|
|
|
6,818 |
|
|
|
5,856 |
|
Purchased power |
|
|
474 |
|
|
|
815 |
|
|
|
515 |
|
Other operations and maintenance |
|
|
3,526 |
|
|
|
3,748 |
|
|
|
3,670 |
|
MC Asset Recovery litigation settlement |
|
|
202 |
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
1,503 |
|
|
|
1,443 |
|
|
|
1,245 |
|
Taxes other than income taxes |
|
|
818 |
|
|
|
797 |
|
|
|
741 |
|
|
Total operating expenses |
|
|
12,475 |
|
|
|
13,621 |
|
|
|
12,027 |
|
|
Operating Income |
|
|
3,268 |
|
|
|
3,506 |
|
|
|
3,326 |
|
Other Income and (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction |
|
|
200 |
|
|
|
152 |
|
|
|
106 |
|
Interest income |
|
|
23 |
|
|
|
33 |
|
|
|
45 |
|
Equity in (losses) income of unconsolidated subsidiaries |
|
|
(1 |
) |
|
|
11 |
|
|
|
(24 |
) |
Leveraged lease income (losses) |
|
|
31 |
|
|
|
(85 |
) |
|
|
40 |
|
Gain on disposition of lease termination |
|
|
26 |
|
|
|
|
|
|
|
|
|
Loss on extinguishment of debt |
|
|
(17 |
) |
|
|
|
|
|
|
|
|
Interest expense, net of amounts capitalized |
|
|
(905 |
) |
|
|
(866 |
) |
|
|
(886 |
) |
Other income (expense), net |
|
|
(21 |
) |
|
|
(29 |
) |
|
|
10 |
|
|
Total other income and (expense) |
|
|
(664 |
) |
|
|
(784 |
) |
|
|
(709 |
) |
|
Earnings Before Income Taxes |
|
|
2,604 |
|
|
|
2,722 |
|
|
|
2,617 |
|
Income taxes |
|
|
896 |
|
|
|
915 |
|
|
|
835 |
|
|
Consolidated Net Income |
|
|
1,708 |
|
|
|
1,807 |
|
|
|
1,782 |
|
Dividends on Preferred and Preference Stock of Subsidiaries |
|
|
65 |
|
|
|
65 |
|
|
|
48 |
|
|
Consolidated Net Income After Dividends on
Preferred and Preference Stock of Subsidiaries |
|
$ |
1,643 |
|
|
$ |
1,742 |
|
|
$ |
1,734 |
|
|
Common Stock Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share (EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS |
|
$ |
2.07 |
|
|
$ |
2.26 |
|
|
$ |
2.29 |
|
Diluted EPS |
|
|
2.06 |
|
|
|
2.25 |
|
|
|
2.28 |
|
|
Average number of shares of common stock outstanding (in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
795 |
|
|
|
771 |
|
|
|
756 |
|
Diluted |
|
|
796 |
|
|
|
775 |
|
|
|
761 |
|
|
Cash dividends paid per share of common stock |
|
$ |
1.7325 |
|
|
$ |
1.6625 |
|
|
$ |
1.595 |
|
|
The accompanying notes are an integral part of these financial statements.
C-32
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income |
|
$ |
1,708 |
|
|
$ |
1,807 |
|
|
$ |
1,782 |
|
Adjustments to reconcile consolidated net income
to net cash provided from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization, total |
|
|
1,788 |
|
|
|
1,704 |
|
|
|
1,486 |
|
Deferred income taxes |
|
|
25 |
|
|
|
215 |
|
|
|
7 |
|
Deferred revenues |
|
|
(54 |
) |
|
|
120 |
|
|
|
(2 |
) |
Allowance for equity funds used during construction |
|
|
(200 |
) |
|
|
(152 |
) |
|
|
(106 |
) |
Equity in (income) losses of unconsolidated subsidiaries |
|
|
1 |
|
|
|
(11 |
) |
|
|
24 |
|
Leveraged lease (income) losses |
|
|
(31 |
) |
|
|
85 |
|
|
|
(40 |
) |
Gain on disposition of lease termination |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
Loss on extinguishment of debt |
|
|
17 |
|
|
|
|
|
|
|
|
|
Pension, postretirement, and other employee benefits |
|
|
(3 |
) |
|
|
21 |
|
|
|
39 |
|
Stock based compensation expense |
|
|
23 |
|
|
|
20 |
|
|
|
28 |
|
Hedge settlements |
|
|
(19 |
) |
|
|
15 |
|
|
|
10 |
|
Other, net |
|
|
79 |
|
|
|
(97 |
) |
|
|
80 |
|
Changes in certain current assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
-Receivables |
|
|
585 |
|
|
|
(176 |
) |
|
|
165 |
|
-Fossil fuel stock |
|
|
(432 |
) |
|
|
(303 |
) |
|
|
(39 |
) |
-Materials and supplies |
|
|
(39 |
) |
|
|
(23 |
) |
|
|
(71 |
) |
-Other current assets |
|
|
(47 |
) |
|
|
(36 |
) |
|
|
|
|
-Accounts payable |
|
|
(125 |
) |
|
|
(74 |
) |
|
|
105 |
|
-Accrued taxes |
|
|
(95 |
) |
|
|
293 |
|
|
|
(19 |
) |
-Accrued compensation |
|
|
(226 |
) |
|
|
36 |
|
|
|
(40 |
) |
-Other current liabilities |
|
|
334 |
|
|
|
20 |
|
|
|
25 |
|
|
Net cash provided from operating activities |
|
|
3,263 |
|
|
|
3,464 |
|
|
|
3,434 |
|
|
Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Property additions |
|
|
(4,670 |
) |
|
|
(3,961 |
) |
|
|
(3,546 |
) |
Investment in restricted cash from pollution control revenue bonds |
|
|
(55 |
) |
|
|
(96 |
) |
|
|
(157 |
) |
Distribution of restricted cash from pollution control revenue bonds |
|
|
119 |
|
|
|
69 |
|
|
|
78 |
|
Nuclear decommissioning trust fund purchases |
|
|
(1,234 |
) |
|
|
(720 |
) |
|
|
(783 |
) |
Nuclear decommissioning trust fund sales |
|
|
1,228 |
|
|
|
712 |
|
|
|
775 |
|
Proceeds from property sales |
|
|
340 |
|
|
|
34 |
|
|
|
33 |
|
Cost of removal, net of salvage |
|
|
(119 |
) |
|
|
(123 |
) |
|
|
(108 |
) |
Change in construction payables |
|
|
215 |
|
|
|
83 |
|
|
|
38 |
|
Other investing activities |
|
|
(143 |
) |
|
|
(124 |
) |
|
|
(39 |
) |
|
Net cash used for investing activities |
|
|
(4,319 |
) |
|
|
(4,126 |
) |
|
|
(3,709 |
) |
|
Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in notes payable, net |
|
|
(306 |
) |
|
|
(314 |
) |
|
|
(669 |
) |
Proceeds |
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt issuances |
|
|
3,042 |
|
|
|
3,687 |
|
|
|
3,826 |
|
Preferred and preference stock |
|
|
|
|
|
|
|
|
|
|
470 |
|
Common stock issuances |
|
|
1,286 |
|
|
|
474 |
|
|
|
538 |
|
Redemptions |
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
(1,234 |
) |
|
|
(1,469 |
) |
|
|
(2,565 |
) |
Redeemable preferred stock |
|
|
|
|
|
|
(125 |
) |
|
|
|
|
Payment of common stock dividends |
|
|
(1,369 |
) |
|
|
(1,280 |
) |
|
|
(1,205 |
) |
Payment of dividends on preferred and preference stock of subsidiaries |
|
|
(65 |
) |
|
|
(66 |
) |
|
|
(40 |
) |
Other financing activities |
|
|
(25 |
) |
|
|
(29 |
) |
|
|
(46 |
) |
|
Net cash provided from financing activities |
|
|
1,329 |
|
|
|
878 |
|
|
|
309 |
|
|
Net Change in Cash and Cash Equivalents |
|
|
273 |
|
|
|
216 |
|
|
|
34 |
|
Cash and Cash Equivalents at Beginning of Year |
|
|
417 |
|
|
|
201 |
|
|
|
167 |
|
|
Cash and Cash Equivalents at End of Year |
|
$ |
690 |
|
|
$ |
417 |
|
|
$ |
201 |
|
|
The accompanying notes are an integral part of these financial statements.
C-33
CONSOLIDATED BALANCE SHEETS
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
Assets |
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
690 |
|
|
$ |
417 |
|
Restricted cash and cash equivalents |
|
|
43 |
|
|
|
103 |
|
Receivables |
|
|
|
|
|
|
|
|
Customer accounts receivable |
|
|
953 |
|
|
|
1,054 |
|
Unbilled revenues |
|
|
394 |
|
|
|
320 |
|
Under recovered regulatory clause revenues |
|
|
333 |
|
|
|
646 |
|
Other accounts and notes receivable |
|
|
375 |
|
|
|
301 |
|
Accumulated provision for uncollectible accounts |
|
|
(25 |
) |
|
|
(26 |
) |
Fossil fuel stock, at average cost |
|
|
1,447 |
|
|
|
1,018 |
|
Materials and supplies, at average cost |
|
|
794 |
|
|
|
757 |
|
Vacation pay |
|
|
145 |
|
|
|
140 |
|
Prepaid expenses |
|
|
508 |
|
|
|
302 |
|
Other regulatory assets, current |
|
|
167 |
|
|
|
275 |
|
Other current assets |
|
|
49 |
|
|
|
51 |
|
|
Total current assets |
|
|
5,873 |
|
|
|
5,358 |
|
|
Property, Plant, and Equipment: |
|
|
|
|
|
|
|
|
In service |
|
|
53,588 |
|
|
|
50,618 |
|
Less accumulated depreciation |
|
|
19,121 |
|
|
|
18,286 |
|
|
Plant in service, net of depreciation |
|
|
34,467 |
|
|
|
32,332 |
|
Nuclear fuel, at amortized cost |
|
|
593 |
|
|
|
510 |
|
Construction work in progress |
|
|
4,170 |
|
|
|
3,036 |
|
|
Total property, plant, and equipment |
|
|
39,230 |
|
|
|
35,878 |
|
|
Other Property and Investments: |
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts, at fair value |
|
|
1,070 |
|
|
|
864 |
|
Leveraged leases |
|
|
610 |
|
|
|
897 |
|
Miscellaneous property and investments |
|
|
283 |
|
|
|
227 |
|
|
Total other property and investments |
|
|
1,963 |
|
|
|
1,988 |
|
|
Deferred Charges and Other Assets: |
|
|
|
|
|
|
|
|
Deferred charges related to income taxes |
|
|
1,047 |
|
|
|
973 |
|
Unamortized debt issuance expense |
|
|
208 |
|
|
|
208 |
|
Unamortized loss on reacquired debt |
|
|
255 |
|
|
|
271 |
|
Deferred under recovered regulatory clause revenues |
|
|
373 |
|
|
|
606 |
|
Other regulatory assets, deferred |
|
|
2,702 |
|
|
|
2,636 |
|
Other deferred charges and assets |
|
|
395 |
|
|
|
429 |
|
|
Total deferred charges and other assets |
|
|
4,980 |
|
|
|
5,123 |
|
|
Total Assets |
|
$ |
52,046 |
|
|
$ |
48,347 |
|
|
The accompanying notes are an integral part of these financial statements.
C-34
CONSOLIDATED BALANCE SHEETS
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Securities due within one year |
|
$ |
1,113 |
|
|
$ |
617 |
|
Notes payable |
|
|
639 |
|
|
|
953 |
|
Accounts payable |
|
|
1,329 |
|
|
|
1,250 |
|
Customer deposits |
|
|
331 |
|
|
|
302 |
|
Accrued taxes |
|
|
|
|
|
|
|
|
Accrued income taxes |
|
|
13 |
|
|
|
197 |
|
Unrecognized tax benefits |
|
|
166 |
|
|
|
131 |
|
Other accrued taxes |
|
|
398 |
|
|
|
396 |
|
Accrued interest |
|
|
218 |
|
|
|
196 |
|
Accrued vacation pay |
|
|
184 |
|
|
|
179 |
|
Accrued compensation |
|
|
248 |
|
|
|
447 |
|
Liabilities from risk management activities |
|
|
125 |
|
|
|
261 |
|
Other regulatory liabilities, current |
|
|
528 |
|
|
|
78 |
|
Other current liabilities |
|
|
292 |
|
|
|
219 |
|
|
Total current liabilities |
|
|
5,584 |
|
|
|
5,226 |
|
|
Long-Term Debt (See accompanying statements) |
|
|
18,131 |
|
|
|
16,816 |
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
|
|
|
Accumulated deferred income taxes |
|
|
6,455 |
|
|
|
6,080 |
|
Deferred credits related to income taxes |
|
|
248 |
|
|
|
259 |
|
Accumulated deferred investment tax credits |
|
|
448 |
|
|
|
455 |
|
Employee benefit obligations |
|
|
2,304 |
|
|
|
2,057 |
|
Asset retirement obligations |
|
|
1,201 |
|
|
|
1,183 |
|
Other cost of removal obligations |
|
|
1,091 |
|
|
|
1,321 |
|
Other regulatory liabilities, deferred |
|
|
278 |
|
|
|
262 |
|
Other deferred credits and liabilities |
|
|
346 |
|
|
|
330 |
|
|
Total deferred credits and other liabilities |
|
|
12,371 |
|
|
|
11,947 |
|
|
Total Liabilities |
|
|
36,086 |
|
|
|
33,989 |
|
|
Redeemable Preferred Stock of Subsidiaries (See accompanying statements) |
|
|
375 |
|
|
|
375 |
|
|
Total Stockholders Equity (See accompanying statements) |
|
|
15,585 |
|
|
|
13,983 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
52,046 |
|
|
$ |
48,347 |
|
|
Commitments and Contingent Matters (See notes) |
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
C-35
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
|
|
(in millions) |
|
(percent of total) |
|
Long-Term Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt payable to affiliated trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity |
|
Interest Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2044 |
|
5.88% |
|
$ |
206 |
|
|
$ |
206 |
|
|
|
|
|
|
|
|
|
Variable rate (3.35% at 1/1/10) due 2042 |
|
|
|
|
206 |
|
|
|
206 |
|
|
|
|
|
|
|
|
|
|
Total long-term debt payable to affiliated trusts |
|
|
|
|
412 |
|
|
|
412 |
|
|
|
|
|
|
|
|
|
|
Long-term senior notes and debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity |
|
Interest Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
4.10% to 7.00% |
|
|
|
|
|
|
128 |
|
|
|
|
|
|
|
|
|
2010 |
|
4.70% |
|
|
102 |
|
|
|
102 |
|
|
|
|
|
|
|
|
|
2011 |
|
4.00% to 5.57% |
|
|
304 |
|
|
|
303 |
|
|
|
|
|
|
|
|
|
2012 |
|
4.85% to 6.25% |
|
|
1,778 |
|
|
|
1,778 |
|
|
|
|
|
|
|
|
|
2013 |
|
4.35% to 6.00% |
|
|
936 |
|
|
|
936 |
|
|
|
|
|
|
|
|
|
2014 |
|
4.15% to 4.90% |
|
|
425 |
|
|
|
75 |
|
|
|
|
|
|
|
|
|
2015 through 2048 |
|
4.25% to 8.20% |
|
|
9,847 |
|
|
|
8,362 |
|
|
|
|
|
|
|
|
|
Adjustable rates (at 1/1/10): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2.3288% to 2.36% |
|
|
|
|
|
|
440 |
|
|
|
|
|
|
|
|
|
2010 |
|
0.35% to 0.97% |
|
|
990 |
|
|
|
1,034 |
|
|
|
|
|
|
|
|
|
2011 |
|
0.68% to 2.95% |
|
|
790 |
|
|
|
490 |
|
|
|
|
|
|
|
|
|
|
Total long-term senior notes and debt |
|
|
|
|
15,172 |
|
|
|
13,648 |
|
|
|
|
|
|
|
|
|
|
Other long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pollution control revenue bonds |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity |
|
Interest Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 through 2048 |
|
1.40% to 6.00% |
|
|
1,973 |
|
|
|
2,030 |
|
|
|
|
|
|
|
|
|
Variable rates (at 1/1/10): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 through 2049 |
|
0.18% to 0.44% |
|
|
1,612 |
|
|
|
1,257 |
|
|
|
|
|
|
|
|
|
|
Total other long-term debt |
|
|
|
|
3,585 |
|
|
|
3,287 |
|
|
|
|
|
|
|
|
|
|
Capitalized lease obligations |
|
|
|
|
98 |
|
|
|
106 |
|
|
|
|
|
|
|
|
|
|
Unamortized debt (discount), net |
|
|
|
|
(23 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
Total long-term debt (annual interest
requirement $894 million) |
|
|
|
|
19,244 |
|
|
|
17,433 |
|
|
|
|
|
|
|
|
|
Less amount due within one year |
|
|
|
|
1,113 |
|
|
|
617 |
|
|
|
|
|
|
|
|
|
|
Long-term debt excluding amount due within one year |
|
|
|
|
18,131 |
|
|
|
16,816 |
|
|
|
53.2 |
% |
|
|
53.9 |
% |
|
C-36
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2009 and 2008
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
(in millions) |
|
(percent of total) |
|
Redeemable Preferred Stock of Subsidiaries: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative preferred stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$100 par or stated value 4.20% to 5.44% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized 20 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding 1 million shares |
|
|
81 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
$1 par value 4.95% to 5.83% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized 28 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding 12 million shares: $25 stated value |
|
|
294 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
Total
redeemable preferred stock of subsidiaries
(annual dividend requirement $20 million) |
|
|
375 |
|
|
|
375 |
|
|
|
1.1 |
|
|
|
1.2 |
|
|
Common Stockholders Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, par value $5 per share |
|
|
4,101 |
|
|
|
3,888 |
|
|
|
|
|
|
|
|
|
Authorized 1 billion shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issued 2009: 820 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008: 778 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury 2009: 0.5 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008: 0.4 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid-in capital |
|
|
2,995 |
|
|
|
1,893 |
|
|
|
|
|
|
|
|
|
Treasury, at cost |
|
|
(15 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
Retained earnings |
|
|
7,885 |
|
|
|
7,612 |
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss) |
|
|
(88 |
) |
|
|
(105 |
) |
|
|
|
|
|
|
|
|
|
Total common stockholders equity |
|
|
14,878 |
|
|
|
13,276 |
|
|
|
43.6 |
|
|
|
42.6 |
|
|
Preferred and Preference Stock of Subsidiaries: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cumulative preferred stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$25 par value 6.00% to 6.13% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized 60 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding 2 million shares |
|
|
45 |
|
|
|
45 |
|
|
|
|
|
|
|
|
|
Preference stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized 65 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding $1 par value 5.63% to 6.50% |
|
|
343 |
|
|
|
343 |
|
|
|
|
|
|
|
|
|
14 million shares (non-cumulative) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$100 par or stated value 6.00% to 6.50% |
|
|
319 |
|
|
|
319 |
|
|
|
|
|
|
|
|
|
3 million shares (non-cumulative) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
preferred and preference stock of subsidiaries
(annual dividend requirement $45 million) |
|
|
707 |
|
|
|
707 |
|
|
|
2.1 |
|
|
|
2.3 |
|
|
Total stockholders equity |
|
|
15,585 |
|
|
|
13,983 |
|
|
|
|
|
|
|
|
|
|
Total Capitalization |
|
$ |
34,091 |
|
|
$ |
31,174 |
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
The accompanying notes are an integral part of these financial statements.
C-37
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
and |
|
|
|
|
Number of |
|
Common Stock |
|
|
|
|
|
Comprehensive |
|
Preference |
|
|
|
|
Common Shares |
|
Par |
|
Paid-In |
|
|
|
|
|
Retained |
|
Income |
|
Stock of |
|
|
|
|
Issued |
|
Treasury |
|
Value |
|
Capital |
|
Treasury |
|
Earnings |
|
(Loss) |
|
Subsidiaries |
|
Total |
|
|
(in thousands) |
|
(in millions) |
Balance at December 31, 2006 |
|
|
751,864 |
|
|
|
(5,594 |
) |
|
$ |
3,759 |
|
|
$ |
1,096 |
|
|
$ |
(192 |
) |
|
$ |
6,765 |
|
|
$ |
(57 |
) |
|
$ |
246 |
|
|
$ |
11,617 |
|
Net income after dividends on
preferred
and preference stock of subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,734 |
|
|
|
|
|
|
|
|
|
|
|
1,734 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
27 |
|
Cumulative effect of new accounting
standards (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(140 |
) |
|
|
|
|
|
|
|
|
|
|
(140 |
) |
Stock issued |
|
|
11,639 |
|
|
|
5,255 |
|
|
|
58 |
|
|
|
356 |
|
|
|
183 |
|
|
|
|
|
|
|
|
|
|
|
461 |
|
|
|
1,058 |
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,204 |
) |
|
|
|
|
|
|
|
|
|
|
(1,204 |
) |
Other |
|
|
|
|
|
|
(60 |
) |
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
763,503 |
|
|
|
(399 |
) |
|
|
3,817 |
|
|
|
1,454 |
|
|
|
(11 |
) |
|
|
7,155 |
|
|
|
(30 |
) |
|
|
707 |
|
|
|
13,092 |
|
Net income after dividends on
preferred
and preference stock of subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,742 |
|
|
|
|
|
|
|
|
|
|
|
1,742 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(75 |
) |
|
|
|
|
|
|
(75 |
) |
Stock issued |
|
|
14,113 |
|
|
|
|
|
|
|
71 |
|
|
|
438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
509 |
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,279 |
) |
|
|
|
|
|
|
|
|
|
|
(1,279 |
) |
Other |
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
1 |
|
|
|
(1 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
(6 |
) |
|
Balance at December 31, 2008 |
|
|
777,616 |
|
|
|
(424 |
) |
|
|
3,888 |
|
|
|
1,893 |
|
|
|
(12 |
) |
|
|
7,612 |
|
|
|
(105 |
) |
|
|
707 |
|
|
|
13,983 |
|
Net income after dividends on
preferred
and preference stock of subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,643 |
|
|
|
|
|
|
|
|
|
|
|
1,643 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
17 |
|
Stock issued |
|
|
42,536 |
|
|
|
|
|
|
|
213 |
|
|
|
1,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,313 |
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,369 |
) |
|
|
|
|
|
|
|
|
|
|
(1,369 |
) |
Other |
|
|
|
|
|
|
(81 |
) |
|
|
|
|
|
|
2 |
|
|
|
(3 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
Balance at December 31, 2009 |
|
|
820,152 |
|
|
|
(505 |
) |
|
$ |
4,101 |
|
|
$ |
2,995 |
|
|
$ |
(15 |
) |
|
$ |
7,885 |
|
|
$ |
(88 |
) |
|
$ |
707 |
|
|
$ |
15,585 |
|
|
The accompanying notes are an integral part of these financial statements.
(a) In 2007 Southern Company recorded two adjustments net of tax in respect of new accounting guidance; a $125 million adjustment in respect of leverage lease transactions and a $15 million adjustment in respect of uncertain tax positions.
C-38
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2009, 2008, and 2007
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(in millions) |
|
|
|
|
|
Consolidated Net Income |
|
$ |
1,708 |
|
|
$ |
1,807 |
|
|
$ |
1,782 |
|
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
Qualifying hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value, net of tax of $(3), $(19),
and $(3), respectively |
|
|
(4 |
) |
|
|
(30 |
) |
|
|
(5 |
) |
Reclassification adjustment for amounts included in net income,
net of tax of $18, $7, and $6, respectively |
|
|
28 |
|
|
|
11 |
|
|
|
9 |
|
Marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value, net of tax of $1, $(4), and $3, respectively |
|
|
4 |
|
|
|
(7 |
) |
|
|
4 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, and $-, respectively |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
Pension and other postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
Benefit plan net gain (loss),net of tax of $(8), $(32),
and $13, respectively |
|
|
(12 |
) |
|
|
(51 |
) |
|
|
20 |
|
Additional prior service costs from amendment to non-qualified
plans, net of tax of $-, $-, and
$(2), respectively |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, and $1, respectively |
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
|
Total other comprehensive income (loss) |
|
|
17 |
|
|
|
(75 |
) |
|
|
27 |
|
|
Dividends on preferred and preference stock of subsidiaries |
|
|
(65 |
) |
|
|
(65 |
) |
|
|
(48 |
) |
|
Consolidated Comprehensive Income |
|
$ |
1,660 |
|
|
$ |
1,667 |
|
|
$ |
1,761 |
|
|
The accompanying notes are an integral part of these financial statements.
C-39
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2009 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (the Company) is the parent company of four traditional operating companies,
Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern
Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern
Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and
indirect subsidiaries. The traditional operating companies, Alabama Power Company (Alabama Power),
Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power
Company (Mississippi Power), are vertically integrated utilities providing electric service in four
Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and
sells electricity at market-based rates in the wholesale market. SCS, the system service company,
provides, at cost, specialized services to Southern Company and its subsidiary companies.
SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its
subsidiary companies and also markets these services to the public and provides fiber cable
services within the Southeast. Southern Holdings is an intermediate holding company subsidiary for
Southern Companys investments in leveraged leases. Southern Nuclear operates and provides
services to Southern Companys 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 is not the
primary beneficiary. All material intercompany transactions have been eliminated in consolidation.
Certain prior years data presented in the financial statements have been reclassified to conform
to the current year presentation.
The traditional operating companies, Southern Power, and certain of their subsidiaries are subject
to regulation by the Federal Energy Regulatory Commission (FERC) and the traditional operating
companies are also subject to regulation by their respective state public service commissions
(PSC). The companies follow accounting principles generally accepted in the United States and
comply with the accounting policies and practices prescribed by their respective commissions. The
preparation of financial statements in conformity with accounting principles generally accepted in
the United States requires the use of estimates, and the actual results may differ from those
estimates.
Related Party Transactions
Alabama Power and Georgia Power purchased synthetic fuel from Alabama Fuel Products, LLC (AFP), an
entity in which Southern Holdings held a 30% ownership interest until July 2006, when its ownership
interest was terminated. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings,
provided fuel transportation services to AFP that were ultimately reflected in the cost of the
synthetic fuel billed to Alabama Power and Georgia Power. Subsequent to the termination of
Southern Companys membership interest in AFP, Alabama Power and Georgia Power continued to
purchase an additional $6 million and $750 million in fuel from AFP in 2008 and 2007, respectively.
SSI continued to provide fuel transportation services of $131 million in 2007, which were
eliminated against fuel expense in the financial statements. SSI also provided other additional
services to AFP and a related party of AFP totaling $47 million in 2007. The synthetic fuel
investments and related party transactions were terminated on December 31, 2007.
C-40
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Regulatory Assets and Liabilities
The traditional operating companies are subject to the provisions of the Financial Accounting
Standards Board in accounting for the effects of rate regulation. Regulatory assets represent
probable future revenues associated with certain costs that are expected to be recovered from
customers through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited to customers
through the ratemaking process. Regulatory assets and (liabilities) reflected in the balance
sheets at December 31 relate to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
Note |
|
|
|
(in millions) |
|
|
|
|
|
Deferred income tax charges |
|
$ |
1,048 |
|
|
$ |
972 |
|
|
|
(a |
) |
Asset retirement obligations-asset |
|
|
125 |
|
|
|
236 |
|
|
|
(a,i |
) |
Asset retirement obligations-liability |
|
|
(47 |
) |
|
|
(5 |
) |
|
|
(a,i |
) |
Other cost of removal obligations |
|
|
(1,307 |
) |
|
|
(1,321 |
) |
|
|
(a |
) |
Deferred income tax credits |
|
|
(249 |
) |
|
|
(260 |
) |
|
|
(a |
) |
Loss on reacquired debt |
|
|
255 |
|
|
|
271 |
|
|
|
(b |
) |
Vacation pay |
|
|
145 |
|
|
|
140 |
|
|
|
(c,i |
) |
Under recovered regulatory clause revenues |
|
|
40 |
|
|
|
432 |
|
|
|
(d |
) |
Over recovered regulatory clause revenues |
|
|
(218 |
) |
|
|
(3 |
) |
|
|
(d |
) |
Building leases |
|
|
47 |
|
|
|
49 |
|
|
|
(f |
) |
Generating plant outage costs |
|
|
39 |
|
|
|
45 |
|
|
|
(d |
) |
Under recovered storm damage costs |
|
|
22 |
|
|
|
27 |
|
|
|
(d |
) |
Property damage reserves |
|
|
(157 |
) |
|
|
(97 |
) |
|
|
(h |
) |
Fuel hedging-asset |
|
|
187 |
|
|
|
314 |
|
|
|
(d |
) |
Fuel hedging-liability |
|
|
(2 |
) |
|
|
(10 |
) |
|
|
(d |
) |
Other assets |
|
|
156 |
|
|
|
163 |
|
|
|
(d |
) |
Environmental remediation-asset |
|
|
68 |
|
|
|
67 |
|
|
|
(h,i |
) |
Environmental remediation-liability |
|
|
(13 |
) |
|
|
(19 |
) |
|
|
(h |
) |
Environmental compliance cost recovery |
|
|
(96 |
) |
|
|
(135 |
) |
|
|
(g |
) |
Other liabilities |
|
|
(51 |
) |
|
|
(43 |
) |
|
|
(j |
) |
Underfunded retiree benefit plans |
|
|
2,268 |
|
|
|
2,068 |
|
|
|
(e,i |
) |
|
Total assets (liabilities), net |
|
$ |
2,260 |
|
|
$ |
2,891 |
|
|
|
|
|
|
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are
as follows: |
|
(a) |
|
Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, other cost of removal, and deferred
tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities
will be settled and trued up following completion of the related activities. Other cost of removal obligations include $216 million at Georgia
Power that may be amortized during 2010 in accordance with the August 27, 2009 Georgia PSC order. See Note 3 under Retail Regulatory Matters
Georgia Power Cost of Removal for additional information. |
|
(b) |
|
Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. |
|
(c) |
|
Recorded as earned by employees and recovered as paid, generally within one year. |
|
(d) |
|
Recorded and recovered or amortized as approved by the appropriate state PSCs over periods not exceeding 10 years. |
|
(e) |
|
Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
|
(f) |
|
Recovered over the remaining lives of the buildings through 2026. |
|
(g) |
|
This balance represents deferred revenue associated with Georgia Powers environmental compliance cost recovery (ECCR) tariff established in its
retail rate plan for the years 2008 through 2010 (2007 Retail Rate Plan). The recovery of the forecasted environmental compliance costs was
levelized to collect equal annual amounts between January 1, 2008 and December 31, 2010 under the tariff. |
|
(h) |
|
Recovered as storm restoration or environmental remediation expenses are incurred. |
|
(i) |
|
Not earning a return as offset in rate base by a corresponding asset or liability. |
|
(j) |
|
Recorded and recovered or amortized as approved by the appropriate state PSC over periods up to the life of the plant or the remaining life of
the original issue or, if refinanced, over the life of the new issue which may range up to 50 years. |
In the event that a portion of a traditional operating companys operations is no longer
subject to applicable accounting rules for rate regulation, such company would be required to write
off or reclassify to accumulated other comprehensive income related regulatory assets and
liabilities that are not specifically recoverable through regulated rates. In addition, the
traditional operating company would be required to determine if any impairment to other assets,
including plant, exists and write down the assets, if impaired, to their fair values. All
regulatory assets and liabilities are to be reflected in rates. See Note 3 under Retail
Regulatory Matters Alabama
Power, Retail Regulatory Matters Georgia Power, and Retail Regulatory Matters Integrated
Coal Gasification Combined Cycle for additional information.
C-41
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Revenues
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate
contract periods. Energy and other revenues are recognized as services are provided. Unbilled
revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for
the traditional operating companies include provisions to adjust billings for fluctuations in fuel
costs, fuel hedging, the energy component of purchased power costs, and certain other costs.
Revenues are adjusted for differences between these actual costs and amounts billed in current
regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance
sheets and are recovered or returned to customers through adjustments to the billing factors.
Retail fuel cost recovery mechanisms vary by each traditional operating company, but in general,
the process requires periodic filings with the appropriate state PSC. Alabama Power continuously
monitors the under/over recovered balance and files for a revised fuel rate when management deems
appropriate. Georgia Power filed a new fuel case on December 15, 2009. The new rates are expected
to become effective April 1, 2010. Gulf Power is required to notify the Florida PSC if the
projected fuel cost over or under recovery exceeds 10% of the projected fuel revenue applicable for
the period and indicate if an adjustment to the fuel cost recovery factor is being requested.
Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually.
See Note 3 under Retail Regulatory Matters Alabama Power Fuel Cost Recovery and Retail
Regulatory Matters Georgia Power Fuel Cost Recovery for additional information.
Southern Company has a diversified base of customers. No single customer or industry comprises 10%
or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of
revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased
emissions allowances as they are used. Fuel expense also includes the amortization of the cost of
nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. See Note 3 under Nuclear Fuel Disposal Costs for additional information.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides
deferred income taxes for all significant income tax temporary differences. Taxes that are
collected from customers on behalf of governmental agencies to be remitted to these agencies are
presented net on the statements of income.
In accordance with regulatory requirements, deferred investment tax credits (ITCs) for the
traditional operating companies are amortized over the lives of the related property with such
amortization normally applied as a credit to reduce depreciation in the statements of income.
Credits amortized in this manner amounted to $24 million in 2009, $23 million in 2008, and $23
million in 2007. At December 31, 2009, all ITCs available to reduce federal income taxes payable
had been utilized.
Under the American Recovery and Reinvestment Act of 2009, certain renewable projects at Southern
Companys non-regulated subsidiaries are eligible for ITCs or cash grants. These non-regulated
companies have elected to receive ITCs. The credits are recorded as a
deferred credit, which will be amortized over the life of the asset,
and the tax basis of the asset is reduced by
50% of the credits received, resulting in a deferred tax asset. The non-regulated companies have
elected to recognize the tax benefit of this basis difference as a reduction to income tax expense
as costs are incurred during the construction period. This basis difference will reverse and be
recorded to income tax expense over the useful life of the asset once placed in service.
In accordance with accounting standards related to the uncertainty in income taxes, Southern
Company recognizes tax positions that are more likely than not of being sustained upon
examination by the appropriate taxing authorities. See Note 5 under Unrecognized Tax Benefits
for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory disallowances and
impairments. Original cost includes: materials; labor; minor items of property; appropriate
administrative and general costs; payroll-related costs such as taxes, pensions, and other
benefits; and the interest capitalized and/or cost of funds used during construction.
C-42
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Southern Companys property, plant, and equipment consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Generation |
|
$ |
28,204 |
|
|
$ |
26,154 |
|
Transmission |
|
|
7,380 |
|
|
|
7,085 |
|
Distribution |
|
|
14,335 |
|
|
|
13,856 |
|
General |
|
|
2,917 |
|
|
|
2,750 |
|
Plant acquisition adjustment |
|
|
43 |
|
|
|
43 |
|
|
Utility plant in service |
|
|
52,879 |
|
|
|
49,888 |
|
|
IT equipment and software |
|
|
182 |
|
|
|
240 |
|
Communications equipment |
|
|
423 |
|
|
|
450 |
|
Other |
|
|
104 |
|
|
|
40 |
|
|
Other plant in service |
|
|
709 |
|
|
|
730 |
|
|
Total plant in service |
|
$ |
53,588 |
|
|
$ |
50,618 |
|
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The
cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance
expense as incurred or performed with the exception of nuclear refueling costs, which are recorded
in accordance with specific state PSC orders. Alabama Power accrues estimated nuclear refueling
costs in advance of the units next refueling outage. Georgia Power defers and amortizes nuclear
refueling costs over the units operating cycle before the next refueling. The refueling cycles
for Alabama Power and Georgia Power range from 18 to 24 months for each unit. In accordance with a
Georgia PSC order, Georgia Power also defers the costs of certain significant inspection costs for
the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which
approximates the expected maintenance cycle.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using
composite straight-line rates, which approximated 3.2% in 2009, 3.2% in 2008, and 3.0% in 2007.
Depreciation studies are conducted periodically to update the composite rates. These studies are
filed with the respective state PSC for the traditional operating companies. Accumulated
depreciation for utility plant in service totaled $18.7 billion and $17.9 billion at December 31,
2009 and 2008, respectively. When property subject to composite depreciation is retired or
otherwise disposed of in the normal course of business, its original cost, together with the cost
of removal, less salvage, is charged to accumulated depreciation. For other property dispositions,
the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a
gain or loss is recognized. Minor items of property included in the original cost of the plant are
retired when the related property unit is retired.
Under Georgia Powers retail rate plan for the three years ended December 31, 2007 (2004 Retail
Rate Plan), Georgia Power was ordered to recognize Georgia PSC-certified capacity costs in rates
evenly over the three years covered by the 2004 Retail Rate Plan. Georgia Power recorded credits
to amortization of $19 million in 2007. The 2007 Retail Rate Plan did not include a similar order.
On August 27, 2009, the Georgia PSC approved an accounting order allowing Georgia Power to
amortize up to $324 million of its regulatory liability related to other cost of removal
obligations. See Note 3 under Retail Regulatory Matters Georgia Power Cost of Removal for
additional information.
In May 2004, the Mississippi PSC approved Mississippi Powers request to reclassify 266 megawatts
(MWs) of Plant Daniel Units 3 and 4 capacity to jurisdictional cost of service effective January 1,
2004 and authorized Mississippi Power to include the related costs and revenue credits in
jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of
retail rate recovery. Mississippi Power amortized the related regulatory liability, pursuant to
the Mississippi PSCs order, by $6 million in 2007 resulting in an increase to earnings in that
year.
Depreciation of the original cost of other plant in service is provided primarily on a
straight-line basis over estimated useful lives ranging from three to 30 years. Accumulated
depreciation for other plant in service totaled $419 million and $433 million at December 31, 2009
and 2008, respectively.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an 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.
The Company has received accounting guidance from the various state PSCs allowing the continued
accrual of
C-43
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
other future retirement costs for long-lived assets that the Company does not have a legal
obligation to retire. Accordingly, the accumulated removal costs for these obligations are
reflected in the balance sheets as a regulatory liability. See Note 3 under Retail Regulatory
Matters Georgia Power Cost of Removal for additional information related to Georgia Powers
cost of removal regulatory liability.
The liability recognized to retire long-lived assets primarily relates to the Companys nuclear
facilities, Plants Farley, Hatch, and Vogtle. The fair value of assets legally restricted for
settling retirement obligations related to nuclear facilities as of December 31, 2009 was $1.1
billion. In addition, the Company has retirement obligations related to various landfill sites,
underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain
transformers. The Company also has identified retirement obligations related to certain
transmission and distribution facilities, co-generation facilities, certain wireless communication
towers, and certain structures authorized by the U.S. Army Corps of Engineers. However,
liabilities for the removal of these assets have not been recorded because the range of time over
which the Company may settle these obligations is unknown and cannot be reasonably estimated. The
Company will continue to recognize in the statements of income allowed removal costs in accordance
with its regulatory treatment. Any differences between costs recognized in accordance with
accounting standards related to asset retirement and environmental obligations, and those reflected
in rates are recognized as either a regulatory asset or liability, as ordered by the various state
PSCs, and are reflected in the balance sheets. See Nuclear Decommissioning herein for further
information on amounts included in rates.
Details of the asset retirement obligations included in the balance sheets are as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Balance beginning of year |
|
$ |
1,185 |
|
|
$ |
1,203 |
|
Liabilities incurred |
|
|
2 |
|
|
|
4 |
|
Liabilities settled |
|
|
(10 |
) |
|
|
(4 |
) |
Accretion |
|
|
77 |
|
|
|
75 |
|
Cash flow revisions |
|
|
(48 |
) |
|
|
(93 |
) |
|
Balance end of year |
|
$ |
1,206 |
|
|
$ |
1,185 |
|
|
Nuclear Decommissioning
The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to
establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama
Power and Georgia Power have external trust funds (the Funds) to comply with the NRCs regulations.
Use of the Funds is restricted to nuclear decommissioning activities and the Funds are managed and
invested in accordance with applicable requirements of various regulatory bodies, including the
NRC, the FERC, and state PSCs, as well as the Internal Revenue Service (IRS). The Funds are
required to be held by one or more trustees with an individual net worth of at least $100 million.
The FERC requires the Funds managers to exercise the standard of care in investing that a prudent
investor would use in the same circumstances. The FERC regulations also require, except for
investments tied to market indices or other mutual funds, that the Funds managers may not invest
in any securities of the utility for which it manages funds or its affiliates. In addition, the
NRC prohibits investments in securities of power reactor licensees. While Southern Company is
allowed to prescribe an overall investment policy to the Funds managers, neither Southern Company
nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds
or to mandate individual investment decisions. Day-to-day management of the investments in the
Funds is delegated to unrelated third party managers with oversight by Southern Company, Alabama
Power, and Georgia Power management. The Funds managers are authorized, within broad limits, to
actively buy and sell securities at their own discretion in order to maximize the investment return
on the Funds investments. The Funds are invested in a tax-efficient manner in a diversified mix
of equity and fixed income securities and are reported as trading securities.
Southern Company records the investment securities held in the Funds at fair value, as disclosed in
Note 10. Gains and losses, whether realized, unrealized, or identified as other-than-temporary,
are recorded in the regulatory liability for asset retirement obligations in the balance sheets and
are not included in net income or other comprehensive income. Fair value adjustments, realized
gains, and other-than-temporary impairment losses are determined on a specific identification
basis.
At December 31, 2009, investment securities in the Funds totaled $1.1 billion consisting of equity
securities of $774 million, debt securities of $272 million, and $22 million of other securities.
At December 31, 2008, investment securities in the Funds totaled $862 million consisting of equity
securities of $518 million, debt securities of $323 million, and $21 million of other securities.
These
amounts exclude receivables related to investment income and pending investment sales, and payables
related to pending investment purchases.
C-44
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Sales of the securities held in the Funds resulted in cash proceeds of $1.2 billion, $712
million, and $775 million in 2009, 2008, and 2007, respectively, all of which were reinvested. For
2009, fair value increases, including reinvested interest and dividends and excluding expenses,
were $215 million, of which $198 million related to securities held in the Funds at December 31,
2009. For 2008, fair value reductions, including reinvested interest and dividends and excluding
expenses, were $(278) million. Realized gains and other-than-temporary impairment losses were $78
million and $(76) million, respectively, in 2007. While the investment securities held in the
Funds are reported as trading securities, the Funds continue to be managed with a long-term focus.
Accordingly, all purchases and sales within the Funds are presented separately in the statement of
cash flows as investing cash flows, consistent with the nature of and purpose for which the
securities were acquired.
Amounts previously recorded in internal reserves are being transferred into the external trust
funds over periods approved by the Alabama PSC. The 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 external
trust funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, 2009, the accumulated provisions for decommissioning were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Farley |
|
Plant Hatch |
|
Plant Vogtle |
|
|
|
|
|
|
(in millions) |
|
|
|
|
External trust funds |
|
$ |
490 |
|
|
$ |
360 |
|
|
$ |
206 |
|
Internal reserves |
|
|
25 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
515 |
|
|
$ |
360 |
|
|
$ |
206 |
|
|
Site study cost is the estimate to decommission a specific facility as of the site study year. The
estimated costs of decommissioning based on the most current studies, which were performed in 2008
for Plant Farley and in 2009 for the Georgia Power plants, were as follows for Alabama Powers
Plant Farley and Georgia Powers ownership interests in Plants Hatch and Vogtle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Farley |
|
Plant Hatch |
|
Plant Vogtle |
Decommissioning periods: |
|
|
|
|
|
|
|
|
|
|
Beginning year |
|
|
2037 |
|
|
|
2034 |
|
|
|
2047 |
|
Completion year |
|
|
2065 |
|
|
|
2063 |
|
|
|
2067 |
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
Site study costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Radiated structures |
|
$ |
1,060 |
|
|
$ |
583 |
|
|
$ |
500 |
|
Non-radiated structures |
|
|
72 |
|
|
|
46 |
|
|
|
71 |
|
|
Total |
|
$ |
1,132 |
|
|
$ |
629 |
|
|
$ |
571 |
|
|
The decommissioning periods and site study costs for Plant Vogtle reflect the extended operating
license approved by the NRC on June 3, 2009. The decommissioning cost estimates are based on
prompt dismantlement and removal of the plant from service. The actual decommissioning costs may
vary from the above estimates because of changes in the assumed date of decommissioning, changes in
NRC requirements, or changes in the assumptions used in making these estimates.
For ratemaking purposes, Alabama 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 as of 2006. The estimates used in current rates are $531
million and $366 million for Plants Hatch and Vogtle, respectively. Amounts expensed were $3
million annually for 2009 and 2008 and $7 million for 2007 for Plant Vogtle. Significant
assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.9%
for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.9% for
Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts
previously contributed to the external trust funds for Plants Hatch and Farley are currently
projected to be adequate to meet the decommissioning obligations.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the traditional operating companies record AFUDC, which
represents the estimated debt and equity costs of capital funds that are necessary to finance the
construction of new regulated facilities. While cash is not realized currently from such
allowance, it increases the revenue requirement over the service life of the plant through a higher
rate base and
higher depreciation. The equity component of AFUDC is not included in calculating taxable income.
Interest related to the construction of new facilities not included in the traditional operating
companies regulated rates is capitalized in accordance with
C-45
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
standard interest capitalization requirements. AFUDC and interest capitalized, net of income
taxes were 15.3%, 11.2%, and 8.4% of net income for 2009, 2008, and 2007, respectively.
Cash payments for interest totaled $788 million, $787 million, and $798 million in 2009, 2008, and
2007, respectively, net of amounts capitalized of $84 million, $71 million, and $64 million,
respectively.
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances
indicate that the carrying value of such assets may not be recoverable. The determination of
whether an impairment has occurred is based on either a specific regulatory disallowance or an
estimate of undiscounted future cash flows attributable to the assets, as compared with the
carrying value of the assets. If an impairment has occurred, the amount of the impairment
recognized is determined by either the amount of regulatory disallowance or by estimating the fair
value of the assets and recording a loss if the carrying value is greater than the fair value. For
assets identified as held for sale, the carrying value is compared to the estimated fair value less
the cost to sell in order to determine if an impairment loss is required. Until the assets are
disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Storm Damage Reserves
Each traditional operating company maintains a reserve to cover the cost of damages from major
storms to its transmission and distribution lines and generally the cost of uninsured damages to
its generation facilities and other property. In accordance with their respective state PSC
orders, the traditional operating companies accrued $44 million in 2009. Alabama Power, Gulf
Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue
certain additional amounts as circumstances warrant. In 2009, such additional accruals totaled $40
million. There were no material accruals for 2008 or 2007.
Leveraged Leases
Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which
relate to international and domestic energy generation, distribution, and transportation assets.
Southern Company receives federal income tax deductions for depreciation and amortization, as well
as interest on long-term debt related to these investments. The Company reviews all important
lease assumptions at least annually, or more frequently if events or changes in circumstances
indicate that a change in assumptions has occurred or may occur. These assumptions include the
effective tax rate, the residual value, the credit quality of the lessees, and the timing of
expected tax cash flows.
Southern Companys net investment in domestic leveraged leases consists of the following at
December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Net rentals receivable |
|
$ |
487 |
|
|
$ |
492 |
|
Unearned income |
|
|
(218 |
) |
|
|
(230 |
) |
|
Investment in leveraged leases |
|
|
269 |
|
|
|
262 |
|
Deferred taxes from leveraged leases |
|
|
(211 |
) |
|
|
(189 |
) |
|
Net investment in leveraged leases |
|
$ |
58 |
|
|
$ |
73 |
|
|
A summary of the components of income from domestic leveraged leases was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Pretax leveraged lease income |
|
$ |
12 |
|
|
$ |
14 |
|
|
$ |
16 |
|
Income tax expense |
|
|
(5 |
) |
|
|
(6 |
) |
|
|
(7 |
) |
|
Net leveraged lease income |
|
$ |
7 |
|
|
$ |
8 |
|
|
$ |
9 |
|
|
C-46
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Southern Companys net investment in international leveraged leases consists of the following
at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Net rentals receivable |
|
$ |
734 |
|
|
$ |
1,298 |
|
Unearned income |
|
|
(393 |
) |
|
|
(663 |
) |
|
Investment in leveraged leases |
|
|
341 |
|
|
|
635 |
|
Current taxes payable |
|
|
|
|
|
|
(120 |
) |
Deferred taxes from leveraged leases |
|
|
(40 |
) |
|
|
(117 |
) |
|
Net investment in leveraged leases |
|
$ |
301 |
|
|
$ |
398 |
|
|
A summary of the components of income from international leveraged leases was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Pretax leveraged lease income (loss) |
|
$ |
19 |
|
|
$ |
(99 |
) |
|
$ |
24 |
|
Income tax benefit (expense) |
|
|
(7 |
) |
|
|
35 |
|
|
|
(8 |
) |
|
Net leveraged lease income (loss) |
|
$ |
12 |
|
|
$ |
(64 |
) |
|
$ |
16 |
|
|
The Company terminated two international leveraged lease investments during 2009. The proceeds
were used to extinguish all debt related to leveraged lease investments, a portion of which had
make-whole redemption provisions. This resulted in a $17 million loss which partially offset a $26
million gain on the terminations.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash
equivalents. Temporary cash investments are securities with original maturities of 90 days or
less.
Materials and Supplies
Generally, materials and supplies include the average costs of transmission, distribution, and
generating plant materials. Materials are charged to inventory when purchased and then expensed or
capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average costs of oil, coal, natural gas, and emissions allowances.
Fuel is charged to inventory when purchased and then expensed as used and recovered by the
traditional operating companies through fuel cost recovery rates approved by each state PSC.
Emissions allowances granted by the Environmental Protection Agency (EPA) are included in inventory
at zero cost.
Financial Instruments
Southern Company uses derivative financial instruments to limit exposure to fluctuations in
interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All
derivative financial instruments are recognized as either assets or liabilities (included in
Other or shown separately as Risk Management Activities) and are measured at fair value. See
Note 10 for additional information. Substantially all of Southern Companys bulk energy purchases
and sales contracts that meet the definition of a derivative are excluded from fair value
accounting requirements because they qualify for the normal scope exception, and are accounted
for under the accrual method. Other derivative contracts qualify as cash flow hedges of
anticipated transactions or are recoverable through the traditional operating companies fuel
hedging programs. This results in the deferral of related gains and losses in other comprehensive
income or regulatory assets and liabilities, respectively, until the hedged transactions occur.
Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other
derivative contracts, including derivatives related to synthetic fuel investments, are marked to
market through current period income and are recorded on a net basis in the statements of income.
See Note 11 for additional information.
C-47
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
The Company does not offset fair value amounts recognized for multiple derivative instruments
executed with the same counterparty under a master netting arrangement. At December 31, 2009, the
amount included in Accounts payable in the balance sheets that the Company has recognized for the
obligation to return cash collateral arising from derivative instruments was not material.
Southern Company is exposed to losses related to financial instruments in the event of
counterparties nonperformance. The Company has established controls to determine and monitor the
creditworthiness of counterparties in order to mitigate the 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, and reclassifications for amounts included in net income.
Accumulated other comprehensive income (loss) balances, net of tax effects, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Other |
|
Accumulated Other |
|
|
Qualifying |
|
Marketable |
|
Postretirement |
|
Comprehensive |
|
|
Hedges |
|
Securities |
|
Benefit Plans |
|
Income (Loss) |
|
|
|
|
|
|
|
|
|
|
(in millions) |
Balance at December 31, 2008 |
|
$ |
(73 |
) |
|
$ |
6 |
|
|
$ |
(38 |
) |
|
$ |
(105 |
) |
Current period change |
|
|
24 |
|
|
|
4 |
|
|
|
(11 |
) |
|
|
17 |
|
|
Balance at December 31, 2009 |
|
$ |
(49 |
) |
|
$ |
10 |
|
|
$ |
(49 |
) |
|
$ |
(88 |
) |
|
Variable Interest Entities
The primary beneficiary of a variable interest entity must consolidate the related assets and
liabilities. Certain of the traditional operating companies have established certain wholly-owned
trusts to issue preferred securities. See Note 6 under Long-Term Debt Payable to Affiliated
Trusts for additional information. However, Southern Company and the applicable traditional
operating companies are not considered the primary beneficiaries of the trusts. Therefore, the
investments in these trusts are reflected as Other Investments, and the related loans from the
trusts are included in Long-term Debt in the balance sheets.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all
employees. The plan is funded in accordance with requirements of the Employee Retirement Income
Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year
ending December 31, 2010. Southern Company also provides certain defined benefit pension plans for
a selected group of management and highly compensated employees. Benefits under these
non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides
certain medical care and life insurance benefits for retired employees through other postretirement
benefit plans. The traditional operating companies fund related trusts to the extent required by
their respective regulatory commissions. For the year ending December 31, 2010, postretirement
trust contributions are expected to total approximately $43 million.
The measurement date for plan assets and obligations for 2009 and 2008 was December 31 while the
measurement date for prior years was September 30. Pursuant to accounting standards related to
defined postretirement benefit plans, Southern Company was required to change the measurement date
for its defined postretirement benefit plans from September 30 to December 31 beginning with the
year ended December 31, 2008. As permitted, Southern Company adopted the measurement date
provisions effective January 1, 2008, resulting in an increase in long-term liabilities of $28
million and an increase in prepaid pension costs of approximately $16 million.
C-48
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Pension Plans
The total accumulated benefit obligation for the pension plans was $6.3 billion in 2009 and $5.5
billion in 2008. Changes during the plan year ended December 31, 2009 and the 15-month period ended
December 31, 2008 in the projected benefit obligations and the fair value of plan assets were as
follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
Change in benefit obligation |
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$ |
5,879 |
|
|
$ |
5,660 |
|
Service cost
|
|
|
146 |
|
|
|
182 |
|
Interest cost
|
|
|
387 |
|
|
|
435 |
|
Benefits paid
|
|
|
(282 |
) |
|
|
(324 |
) |
Actuarial loss (gain)
|
|
|
628 |
|
|
|
(74 |
) |
|
Balance at end of year
|
|
|
6,758 |
|
|
|
5,879 |
|
|
Change in plan assets |
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
5,093 |
|
|
|
7,624 |
|
Actual return (loss) on plan assets
|
|
|
792 |
|
|
|
(2,234 |
) |
Employer contributions
|
|
|
24 |
|
|
|
27 |
|
Benefits paid
|
|
|
(282 |
) |
|
|
(324 |
) |
|
Fair value of plan assets at end of year
|
|
|
5,627 |
|
|
|
5,093 |
|
|
Accrued liability
|
|
$ |
(1,131 |
) |
|
$ |
(786 |
) |
|
At December 31, 2009, the projected benefit obligations for the qualified and non-qualified pension
plans were $6.3 billion and $0.4 billion, respectively. All pension plan assets are related to the
qualified pension plan.
Pension plan assets are managed and invested in accordance with all applicable requirements,
including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). In
2009, in determining the optimal asset allocation for the pension fund, the Company performed an
extensive study based on projections of both assets and liabilities over a 10-year forward horizon.
The primary goal of the study was to maximize plan funded status. The Companys investment policy
covers a diversified mix of assets, including equity and fixed income securities, real estate, and
private equity. Derivative instruments are used primarily to gain efficient exposure to the
various asset classes and as hedging tools. The Company minimizes the risk of large losses
primarily through diversification but also monitors and manages other aspects of risk. The actual
composition of the Companys pension plan assets as of December 31, 2009 and 2008, along with the
targeted mix of assets, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target |
|
|
2009 |
|
|
2008 |
|
Domestic equity |
|
|
29 |
% |
|
|
33 |
% |
|
|
34 |
% |
International equity |
|
|
28 |
|
|
|
29 |
|
|
|
23 |
|
Fixed income |
|
|
15 |
|
|
|
15 |
|
|
|
14 |
|
Special situations |
|
|
3 |
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
15 |
|
|
|
13 |
|
|
|
19 |
|
Private equity |
|
|
10 |
|
|
|
10 |
|
|
|
10 |
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
The investment strategy for plan assets related to the Companys defined benefit plan is to be
broadly diversified across major asset classes. The asset allocation is established after
consideration of various factors that affect the assets and liabilities of the pension plan
including, but not limited to, historical and expected returns, volatility, correlations of asset
classes, the current level of assets and liabilities, and the assumed growth in assets and
liabilities. Because a significant portion of the liability of the pension plan is long-term in
nature, the assets are invested consistent with long-term investment expectations for return and
risk. To manage the actual asset class exposures relative to the target asset allocation, the
Company employs a formal rebalancing program. As additional risk management, external investment
managers and service providers are subject to written guidelines to ensure appropriate and prudent
investment practices.
C-49
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Detailed below is a description of the investment strategies for each major asset category
disclosed above:
|
|
Domestic equity. This portion of the portfolio comprises a mix of large and small
capitalization stocks with generally an equal distribution of value and growth attributes
managed both actively and through passive index approaches. |
|
|
|
International equity. This portion of the portfolio is actively managed with a blend of
growth stocks and value stocks with both developed and emerging market exposure. |
|
|
|
Fixed income. This portion of the portfolio is actively managed through an allocation to
long-dated, investment grade corporate and government bonds. |
|
|
|
Special situations. Though currently unfunded, this portion of the portfolio was established
both to execute opportunistic investment strategies with the objectives of diversifying and
enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising
new strategies of a longer-term nature. |
|
|
|
Real estate investments. Assets in this portion of the portfolio are invested in traditional
private market, equity-oriented investments in real properties (indirectly through pooled
funds or partnerships) and in publicly traded real estate securities. |
|
|
|
Private equity. This portion of the portfolio generally consists of investments in private
partnerships that invest in private or public securities typically through privately
negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed
debt are examples of investment strategies within this category. |
The fair values of pension plan assets as of December 31, 2009 and 2008 are presented below. These
fair value measurements exclude cash, receivables related to investment income, pending investments
sales, and payables related to pending investment purchases.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted Prices |
|
|
|
|
|
|
|
|
in Active Markets for |
|
Significant Other |
|
Significant |
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
|
|
Assets |
|
Inputs |
|
Inputs |
|
|
As of December 31, 2009: |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Total |
|
|
(in millions) |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity* |
|
$ |
1,117 |
|
|
$ |
462 |
|
|
$ |
|
|
|
$ |
1,579 |
|
International equity* |
|
|
1,444 |
|
|
|
144 |
|
|
|
|
|
|
|
1,588 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury, government, and agency bonds |
|
|
|
|
|
|
416 |
|
|
|
|
|
|
|
416 |
|
Mortgage- and asset-backed securities |
|
|
|
|
|
|
113 |
|
|
|
|
|
|
|
113 |
|
Corporate bonds |
|
|
|
|
|
|
279 |
|
|
|
|
|
|
|
279 |
|
Pooled funds |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
10 |
|
Cash equivalents and other |
|
|
3 |
|
|
|
341 |
|
|
|
|
|
|
|
344 |
|
Special situations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
174 |
|
|
|
|
|
|
|
547 |
|
|
|
721 |
|
Private equity |
|
|
|
|
|
|
|
|
|
|
555 |
|
|
|
555 |
|
|
Total |
|
$ |
2,738 |
|
|
$ |
1,765 |
|
|
$ |
1,102 |
|
|
$ |
5,605 |
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
|
(5 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(6 |
) |
|
Total |
|
$ |
2,733 |
|
|
$ |
1,764 |
|
|
$ |
1,102 |
|
|
$ |
5,599 |
|
|
|
|
|
* |
|
Level 1 securities consist of actively traded stocks while Level 2 securities consist of
pooled funds. Management believes that the portfolio is well-diversified with no
significant concentrations of risk. |
C-50
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
Quoted Prices |
|
|
|
|
|
|
|
|
|
|
|
|
in Active Markets for |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
Identical |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Assets |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
As of December 31, 2008: |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
|
(in millions) |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity* |
|
$ |
1,049 |
|
|
$ |
427 |
|
|
$ |
|
|
|
$ |
1,476 |
|
International equity* |
|
|
944 |
|
|
|
87 |
|
|
|
|
|
|
|
1,031 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury, government, and agency bonds |
|
|
|
|
|
|
441 |
|
|
|
|
|
|
|
441 |
|
Mortgage- and asset-backed securities |
|
|
|
|
|
|
209 |
|
|
|
|
|
|
|
209 |
|
Corporate bonds |
|
|
|
|
|
|
286 |
|
|
|
|
|
|
|
286 |
|
Pooled funds |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Cash equivalents and other |
|
|
22 |
|
|
|
202 |
|
|
|
|
|
|
|
224 |
|
Special situations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
144 |
|
|
|
|
|
|
|
839 |
|
|
|
983 |
|
Private equity |
|
|
|
|
|
|
|
|
|
|
490 |
|
|
|
490 |
|
|
Total |
|
$ |
2,159 |
|
|
$ |
1,655 |
|
|
$ |
1,329 |
|
|
$ |
5,143 |
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
(8 |
) |
|
Total |
|
$ |
2,151 |
|
|
$ |
1,655 |
|
|
$ |
1,329 |
|
|
$ |
5,135 |
|
|
|
|
|
* |
|
Level 1 securities consist of actively traded stocks while Level 2 securities consist of
pooled funds. Management believes that the portfolio is well-diversified with no
significant concentrations of risk. |
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued
using significant unobservable inputs for the years ended December 31, 2009 and 2008 are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Real Estate |
|
|
|
|
|
Real Estate |
|
|
|
|
Investments |
|
Private Equity |
|
Investments |
|
Private Equity |
|
|
|
|
|
|
(in millions) |
|
|
|
|
Beginning balance |
|
$ |
839 |
|
|
$ |
490 |
|
|
$ |
1,045 |
|
|
$ |
520 |
|
Actual return on investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related to investments held at year end |
|
|
(240 |
) |
|
|
37 |
|
|
|
(170 |
) |
|
|
(141 |
) |
Related to investments sold during the year |
|
|
(65 |
) |
|
|
10 |
|
|
|
4 |
|
|
|
25 |
|
|
Total return on investments |
|
|
(305 |
) |
|
|
47 |
|
|
|
(166 |
) |
|
|
(116 |
) |
Purchases, sales, and settlements |
|
|
13 |
|
|
|
18 |
|
|
|
(40 |
) |
|
|
86 |
|
Transfers into/out of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
547 |
|
|
$ |
555 |
|
|
$ |
839 |
|
|
$ |
490 |
|
|
The fair values presented above are prepared in accordance with applicable accounting standards
regarding fair value. For purposes of determining the fair value of the pension plan assets and
the appropriate level designation, management relies on information provided by the plans trustee.
This information is reviewed and evaluated by management with changes made to the trustee
information as appropriate.
C-51
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Securities for which the activity is observable on an active market or traded exchange are
categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix
pricing, a common model using observable inputs. Domestic and international equity securities
classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but
where the value is determined using observable inputs from the market. Securities that are valued
using unobservable inputs are classified as Level 3 and include investments in real estate and
investments in limited partnerships. The Company invests (through the pension plan trustee)
directly in the limited partnerships which then invest in various types of funds or various private
entities within a fund. The fair value of the limited partnerships investments is based on
audited annual capital accounts statements which are generally prepared on a fair value basis. The
Company also relies on the fact that, in most instances, the underlying assets held by the limited
partnerships are reported at fair value. External investment managers typically send valuations to
both the custodian and to the Company within 90 days of quarter end. The custodian reports the
most recent value available and adjusts the value for cash flows since the statement date for each
respective fund.
Amounts recognized in the consolidated balance sheets related to the Companys pension plans
consist of the following:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Other regulatory assets, deferred |
|
$ |
1,894 |
|
|
$ |
1,579 |
|
Other current liabilities |
|
|
(25 |
) |
|
|
(23 |
) |
Employee benefit obligations |
|
|
(1,106 |
) |
|
|
(763 |
) |
Accumulated other comprehensive income |
|
|
74 |
|
|
|
54 |
|
|
Presented below are the amounts included in accumulated other comprehensive income and regulatory
assets at December 31, 2009 and 2008 related to the defined benefit pension plans that had not yet
been recognized in net periodic pension cost along with the estimated amortization of such amounts
for 2010.
|
|
|
|
|
|
|
|
|
|
|
Prior Service Cost |
|
Net (Gain)Loss |
|
|
(in millions) |
Balance at December 31, 2009: |
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
10 |
|
|
$ |
64 |
|
Regulatory assets |
|
|
188 |
|
|
|
1,706 |
|
|
Total |
|
$ |
198 |
|
|
$ |
1,770 |
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008: |
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
12 |
|
|
$ |
42 |
|
Regulatory assets |
|
|
220 |
|
|
|
1,359 |
|
|
Total |
|
$ |
232 |
|
|
$ |
1,401 |
|
|
|
|
|
|
|
|
|
|
|
Estimated amortization in net periodic
pension cost in 2010: |
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
1 |
|
|
$ |
1 |
|
Regulatory assets |
|
|
31 |
|
|
|
9 |
|
|
Total |
|
$ |
32 |
|
|
$ |
10 |
|
|
C-52
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
The components of other comprehensive income, along with the changes in the balances of regulatory
assets and regulatory liabilities, related to the defined benefit pension plans for the year ended
December 31, 2009 and the 15 months ended December 31, 2008 are presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
Regulatory |
|
Regulatory |
|
|
Comprehensive Income |
|
Assets |
|
Liabilities |
|
|
(in millions) |
Balance at December 31, 2007 |
|
$ |
(26 |
) |
|
$ |
188 |
|
|
$ |
(1,288 |
) |
Net loss |
|
|
83 |
|
|
|
1,412 |
|
|
|
1,322 |
|
Change in prior service costs |
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service costs |
|
|
(2 |
) |
|
|
(10 |
) |
|
|
(34 |
) |
Amortization of net gain |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
|
|
|
Total reclassification adjustments |
|
|
(3 |
) |
|
|
(21 |
) |
|
|
(34 |
) |
|
Total change |
|
|
80 |
|
|
|
1,391 |
|
|
|
1,288 |
|
|
Balance at December 31, 2008 |
|
|
54 |
|
|
|
1,579 |
|
|
|
|
|
Net loss |
|
|
21 |
|
|
|
355 |
|
|
|
|
|
Change in prior service costs |
|
|
|
|
|
|
1 |
|
|
|
|
|
Reclassification adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service costs |
|
|
(1 |
) |
|
|
(34 |
) |
|
|
|
|
Amortization of net gain |
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
Total reclassification adjustments |
|
|
(1 |
) |
|
|
(41 |
) |
|
|
|
|
|
Total change |
|
|
20 |
|
|
|
315 |
|
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
74 |
|
|
$ |
1,894 |
|
|
$ |
|
|
|
Components of net periodic pension cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Service cost |
|
$ |
146 |
|
|
$ |
146 |
|
|
$ |
147 |
|
Interest cost |
|
|
387 |
|
|
|
348 |
|
|
|
324 |
|
Expected return on plan assets |
|
|
(541 |
) |
|
|
(525 |
) |
|
|
(481 |
) |
Recognized net loss |
|
|
7 |
|
|
|
9 |
|
|
|
10 |
|
Net amortization |
|
|
35 |
|
|
|
37 |
|
|
|
35 |
|
|
Net periodic pension cost |
|
$ |
34 |
|
|
$ |
15 |
|
|
$ |
35 |
|
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against
the expected return on plan assets. The expected return on plan assets is determined by
multiplying the expected rate of return on plan assets and the market-related value of plan assets.
In determining the market-related value of plan assets, the Company has elected to amortize
changes in the market value of all plan assets over five years rather than recognize the changes
immediately. As a result, the accounting value of plan assets that is used to calculate the
expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used
to measure the projected benefit obligation for the pension plans. At December 31, 2009, estimated
benefit payments were as follows:
|
|
|
|
|
|
|
Benefit Payments |
|
|
(in millions) |
2010 |
|
$ |
323 |
|
2011 |
|
|
341 |
|
2012 |
|
|
360 |
|
2013 |
|
|
383 |
|
2014 |
|
|
417 |
|
2015 to 2019 |
|
|
2,456 |
|
|
C-53
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Other Postretirement Benefits
Changes during the plan year ended December 31, 2009 and the 15-month period ended December 31,
2008 in the accumulated postretirement benefit obligations (APBO) and in the fair value of plan
assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Change in benefit obligation |
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
1,733 |
|
|
$ |
1,797 |
|
Service cost |
|
|
26 |
|
|
|
36 |
|
Interest cost |
|
|
113 |
|
|
|
138 |
|
Benefits paid |
|
|
(93 |
) |
|
|
(108 |
) |
Actuarial loss (gain) |
|
|
34 |
|
|
|
(139 |
) |
Plan amendments |
|
|
(59 |
) |
|
|
|
|
Retiree drug subsidy |
|
|
5 |
|
|
|
9 |
|
|
Balance at end of year |
|
|
1,759 |
|
|
|
1,733 |
|
|
Change in plan assets |
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
631 |
|
|
|
820 |
|
Actual return (loss) on plan assets |
|
|
127 |
|
|
|
(232 |
) |
Employer contributions |
|
|
72 |
|
|
|
142 |
|
Benefits paid |
|
|
(87 |
) |
|
|
(99 |
) |
|
Fair value of plan assets at end of year |
|
|
743 |
|
|
|
631 |
|
|
Accrued liability |
|
$ |
(1,016 |
) |
|
$ |
(1,102 |
) |
|
Other postretirement benefit plan assets are managed and invested in accordance with all applicable
requirements, including ERISA and the Internal Revenue Code. The Companys investment policy
covers a diversified mix of assets, including equity and fixed income securities, real estate, and
private equity. Derivative instruments are used primarily to gain efficient exposure to the
various asset classes and as hedging tools. The Company minimizes the risk of large losses
primarily through diversification but also monitors and manages other aspects of risk. The actual
composition of the Companys other postretirement benefit plan assets as of the end of the year,
along with the targeted mix of assets, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target |
|
2009 |
|
2008 |
Domestic equity |
|
|
42 |
% |
|
|
37 |
% |
|
|
34 |
% |
International equity |
|
|
19 |
|
|
|
24 |
|
|
|
18 |
|
Fixed income |
|
|
30 |
|
|
|
32 |
|
|
|
38 |
|
Special situations |
|
|
1 |
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
5 |
|
|
|
4 |
|
|
|
7 |
|
Private equity |
|
|
3 |
|
|
|
3 |
|
|
|
3 |
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
Detailed below is a description of the investment strategies for each major asset category
disclosed above:
|
|
Domestic equity. This portion of the portfolio comprises a mix of large and small
capitalization stocks with generally an equal distribution of value and growth attributes
managed both actively and through passive index approaches. |
|
|
|
International equity. This portion of the portfolio is actively managed with a blend of
growth stocks and value stocks with both developed and emerging market exposure. |
|
|
|
Fixed income. This portion of the portfolio is actively managed through an allocation to
long-dated, investment grade corporate and government bonds. |
|
|
|
Special situations. Though currently unfunded, this portion of the portfolio was established
both to execute opportunistic investment strategies with the objectives of diversifying and
enhancing returns and exploiting short-term inefficiencies, as well as to invest in promising
new strategies of a longer-term nature. |
|
|
|
Trust-owned life insurance. Some of the Companys taxable trusts invest in these investments
in order to minimize the impact of taxes on the portfolio. |
|
|
|
Real estate investments. Assets in this portion of the portfolio are invested in traditional
private market, equity-oriented investments in real properties (indirectly through pooled
funds or partnerships) and in publicly traded real estate securities. |
C-54
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
Private equity. This portion of the portfolio generally consists of investments in private
partnerships that invest in private or public securities typically through privately
negotiated and/or structured transactions. Leveraged buyouts, venture capital, and distressed
debt are examples of investment strategies within this category. |
The fair values of other postretirement benefit plan assets as of December 31, 2009 and 2008 are
presented below. These fair value measurements exclude cash, receivables related to investment
income, pending investments sales, and payables related to pending investment purchases.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted Prices |
|
|
|
|
|
|
|
|
in Active |
|
Significant |
|
|
|
|
|
|
Markets for |
|
Other |
|
Significant |
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
|
|
Assets |
|
Inputs |
|
Inputs |
|
|
As of December 31, 2009: |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Total |
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity* |
|
$ |
149 |
|
|
$ |
42 |
|
|
$ |
|
|
|
$ |
191 |
|
International equity* |
|
|
62 |
|
|
|
36 |
|
|
|
|
|
|
|
98 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury, government, and agency bonds |
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Mortgage- and asset-backed securities |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
5 |
|
Corporate bonds |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Pooled funds |
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
18 |
|
Cash equivalents and other |
|
|
|
|
|
|
54 |
|
|
|
|
|
|
|
54 |
|
Trust-owned life insurance |
|
|
|
|
|
|
270 |
|
|
|
|
|
|
|
270 |
|
Special situations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
7 |
|
|
|
|
|
|
|
24 |
|
|
|
31 |
|
Private equity |
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
24 |
|
|
Total |
|
$ |
218 |
|
|
$ |
459 |
|
|
$ |
48 |
|
|
$ |
725 |
|
|
* |
|
Level 1 securities consist of actively traded stocks while Level 2 securities consist of
pooled funds. Management believes that the portfolio is well-diversified with no
significant concentrations of risk. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted Prices |
|
|
|
|
|
|
|
|
in Active |
|
Significant |
|
|
|
|
|
|
Markets for |
|
Other |
|
Significant |
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
|
|
Assets |
|
Inputs |
|
Inputs |
|
|
As of December 31, 2008: |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Total |
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity* |
|
$ |
114 |
|
|
$ |
47 |
|
|
$ |
|
|
|
$ |
161 |
|
International equity* |
|
|
41 |
|
|
|
24 |
|
|
|
|
|
|
|
65 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury, government, and agency bonds |
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Mortgage- and asset-backed securities |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Corporate bonds |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Pooled funds |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Cash equivalents and other |
|
|
1 |
|
|
|
73 |
|
|
|
|
|
|
|
74 |
|
Trust-owned life insurance |
|
|
|
|
|
|
215 |
|
|
|
|
|
|
|
215 |
|
Special situations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate investments |
|
|
6 |
|
|
|
|
|
|
|
36 |
|
|
|
42 |
|
Private equity |
|
|
|
|
|
|
|
|
|
|
21 |
|
|
|
21 |
|
|
Total |
|
$ |
162 |
|
|
$ |
412 |
|
|
$ |
57 |
|
|
$ |
631 |
|
|
|
|
|
* |
|
Level 1 securities consist of actively traded stocks while Level 2 securities consist of
pooled funds. Management believes that the portfolio is well-diversified with no
significant concentrations of risk. |
C-55
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit
plan assets valued using significant unobservable inputs for the years ended December 31, 2009 and
2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Real Estate |
|
|
|
|
|
Real Estate |
|
|
|
|
Investments |
|
Private Equity |
|
Investments |
|
Private Equity |
|
|
(in millions) |
Beginning balance |
|
$ |
36 |
|
|
$ |
21 |
|
|
$ |
44 |
|
|
$ |
22 |
|
Actual return on investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related to investments held at year end |
|
|
(10 |
) |
|
|
2 |
|
|
|
(6 |
) |
|
|
(6 |
) |
Related to
investments sold during the year |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
Total return on investments |
|
|
(13 |
) |
|
|
2 |
|
|
|
(6 |
) |
|
|
(5 |
) |
Purchases, sales, and settlements |
|
|
1 |
|
|
|
1 |
|
|
|
(2 |
) |
|
|
4 |
|
Transfers into/out of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
24 |
|
|
$ |
24 |
|
|
$ |
36 |
|
|
$ |
21 |
|
|
The fair values presented above are prepared in accordance with applicable accounting standards
regarding fair value. For purposes of determining the fair value of the pension plan assets and
the appropriate level designation, management relies on information provided by the plans trustee.
This information is reviewed and evaluated by management with changes made to the trustee
information as appropriate.
Securities for which the activity is observable on an active market or traded exchange are
categorized as Level 1. Fixed income securities classified as Level 2 are valued using matrix
pricing, a common model using observable inputs. Domestic and international equity securities
classified as Level 2 consist of pooled funds where the value is not quoted on an exchange but
where the value is determined using observable inputs from the market. Securities that are valued
using unobservable inputs are classified as Level 3 and include investments in real estate and
investments in limited partnerships. The Company invests (through the pension plan trustee)
directly in the limited partnerships which then invest in various types of funds or various private
entities within a fund. The fair value of the limited partnerships investments is based on
audited annual capital accounts statements which are generally prepared on a fair value basis. The
Company also relies on the fact that, in most instances, the underlying assets held by the limited
partnerships are reported at fair value. External investment managers typically send valuations to
both the custodian and to the Company within 90 days of quarter end. The custodian reports the
most recent value available and adjusts the value for cash flows since the statement date for each
respective fund.
Amounts recognized in the balance sheets related to the Companys other postretirement benefit
plans consist of the following:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Other regulatory assets, deferred |
|
$ |
374 |
|
|
$ |
489 |
|
Other current liabilities |
|
|
|
|
|
|
(3 |
) |
Employee benefit obligations |
|
|
(1,016 |
) |
|
|
(1,099 |
) |
Accumulated other comprehensive income |
|
|
5 |
|
|
|
8 |
|
|
C-56
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Presented below are the amounts included in accumulated other comprehensive income and regulatory
assets at December 31, 2009 and 2008 related to the other postretirement benefit plans that had not
yet been recognized in net periodic postretirement benefit cost along with the estimated
amortization of such amounts for 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior Service |
|
Net (Gain) |
|
Transition |
|
|
Cost |
|
Loss |
|
Obligation |
|
|
(in millions) |
Balance at December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
|
|
|
$ |
5 |
|
|
$ |
|
|
Regulatory assets |
|
|
41 |
|
|
|
298 |
|
|
|
35 |
|
|
Total |
|
$ |
41 |
|
|
$ |
303 |
|
|
$ |
35 |
|
|
Balance at December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
3 |
|
|
$ |
5 |
|
|
$ |
|
|
Regulatory assets |
|
|
88 |
|
|
|
335 |
|
|
|
66 |
|
|
Total |
|
$ |
91 |
|
|
$ |
340 |
|
|
$ |
66 |
|
|
Estimated amortization as net periodic postretirement benefit cost in 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Regulatory assets |
|
|
5 |
|
|
|
5 |
|
|
|
10 |
|
|
Total |
|
$ |
5 |
|
|
$ |
5 |
|
|
$ |
10 |
|
|
The components of other comprehensive income, along with the changes in the balance of regulatory
assets, related to the other postretirement benefit plans for the plan year ended December 31, 2009
and the 15 months ended December 31, 2008 are presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
Regulatory |
|
|
Comprehensive Income |
|
Assets |
|
|
(in millions) |
Balance at December 31, 2007 |
|
$ |
8 |
|
|
$ |
360 |
|
Net loss |
|
|
1 |
|
|
|
166 |
|
Change in prior service costs/transition obligation |
|
|
|
|
|
|
|
|
Reclassification adjustments: |
|
|
|
|
|
|
|
|
Amortization of transition obligation |
|
|
|
|
|
|
(18 |
) |
Amortization of prior service costs |
|
|
(1 |
) |
|
|
(11 |
) |
Amortization of net gain |
|
|
|
|
|
|
(8 |
) |
|
Total reclassification adjustments |
|
|
(1 |
) |
|
|
(37 |
) |
|
Total change |
|
|
|
|
|
|
129 |
|
|
Balance at December 31, 2008 |
|
|
8 |
|
|
|
489 |
|
Net loss (gain) |
|
|
|
|
|
|
(33 |
) |
Change in prior service costs/transition obligation |
|
|
(3 |
) |
|
|
(56 |
) |
Reclassification adjustments: |
|
|
|
|
|
|
|
|
Amortization of transition obligation |
|
|
|
|
|
|
(13 |
) |
Amortization of prior service costs |
|
|
|
|
|
|
(8 |
) |
Amortization of net gain |
|
|
|
|
|
|
(5 |
) |
|
Total reclassification adjustments |
|
|
|
|
|
|
(26 |
) |
|
Total change |
|
|
(3 |
) |
|
|
(115 |
) |
|
Balance at December 31, 2009 |
|
$ |
5 |
|
|
$ |
374 |
|
|
C-57
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Components of the other postretirement benefit plans net periodic cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Service cost |
|
$ |
26 |
|
|
$ |
28 |
|
|
$ |
27 |
|
Interest cost |
|
|
113 |
|
|
|
111 |
|
|
|
107 |
|
Expected return on plan assets |
|
|
(61 |
) |
|
|
(59 |
) |
|
|
(52 |
) |
Net amortization |
|
|
25 |
|
|
|
31 |
|
|
|
38 |
|
|
Net postretirement cost |
|
$ |
103 |
|
|
$ |
111 |
|
|
$ |
120 |
|
|
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act) provides
a 28% prescription drug subsidy for Medicare eligible retirees. The effect of the subsidy reduced
Southern Companys expenses for the years ended December 31, 2009, 2008, and 2007 by approximately
$33 million, $35 million, and $35 million, respectively.
Future benefit payments, including prescription drug benefits, reflect expected future service and
are estimated based on assumptions used to measure the accumulated benefit obligation for the
postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as
a result of the Medicare Act as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Payments |
|
Subsidy Receipts |
|
Total |
|
|
(in millions) |
2010 |
|
$ |
107 |
|
|
$ |
(8 |
) |
|
$ |
99 |
|
2011 |
|
|
117 |
|
|
|
(9 |
) |
|
|
108 |
|
2012 |
|
|
123 |
|
|
|
(11 |
) |
|
|
112 |
|
2013 |
|
|
129 |
|
|
|
(12 |
) |
|
|
117 |
|
2014 |
|
|
134 |
|
|
|
(14 |
) |
|
|
120 |
|
2015 to 2019 |
|
|
722 |
|
|
|
(93 |
) |
|
|
629 |
|
|
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the benefit
obligations as of the measurement date and the net periodic costs for the pension and other
postretirement benefit plans for the following year are presented below. Net periodic benefit
costs were calculated in 2006 for the 2007 plan year using a discount rate of 6.00% and an annual
salary increase of 3.50%.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
Discount rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Pension plans |
|
|
5.93 |
% |
|
|
6.75 |
% |
|
|
6.30 |
% |
Other postretirement benefit plans |
|
|
5.83 |
|
|
|
6.75 |
|
|
|
6.30 |
|
Annual salary increase |
|
|
4.18 |
|
|
|
3.75 |
|
|
|
3.75 |
|
Long-term return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Pension plans |
|
|
8.50 |
|
|
|
8.50 |
|
|
|
8.50 |
|
Other postretirement benefit plans |
|
|
7.51 |
|
|
|
7.59 |
|
|
|
7.58 |
|
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit
plan assets using a financial model to project the expected return on each current investment
portfolio. The analysis projects an expected rate of return on each of seven different asset
classes in order to arrive at the expected return on the entire portfolio relying on each 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 asset allocation, an anticipated inflation rate, and the projected impact of a periodic
rebalancing of each trusts portfolio.
C-58
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
An additional assumption used in measuring the APBO was a weighted average medical care cost trend
rate of 8.50% for 2010, decreasing gradually to 5.25% through the year 2016 and remaining at that
level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1%
would affect the APBO and the service and interest cost components at December 31, 2009 as follows:
|
|
|
|
|
|
|
|
|
|
|
1 Percent |
|
1 Percent |
|
|
Increase |
|
Decrease |
|
|
(in millions) |
Benefit obligation |
|
$ |
115 |
|
|
$ |
102 |
|
Service and interest costs |
|
|
9 |
|
|
|
9 |
|
|
Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering substantially all
employees. The Company provides an 85% matching contribution up to 6% of an employees base
salary. Total matching contributions made to the plan for 2009, 2008, and 2007 were $78 million,
$76 million, and $73 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in
the ordinary course of business. In addition, the business activities of Southern 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 opacity and air
and water quality standards, has increased generally throughout the United States. In particular,
personal injury and other claims for damages caused by alleged exposure to hazardous materials, and
common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse
gas and other emissions, have become more frequent. The ultimate outcome of such pending or
potential litigation against Southern Company and its subsidiaries cannot be predicted at this
time; however, for current proceedings not specifically reported herein, management does not
anticipate that the liabilities, if any, arising from such current proceedings would have a
material adverse effect on Southern Companys financial statements.
Mirant Matters
Mirant Corporation (Mirant) was an energy company with businesses that included independent power
projects and energy trading and risk management companies in the U.S. and selected other countries.
It was a wholly-owned subsidiary of Southern Company until its initial public offering in October
2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining
ownership, and Mirant became an independent corporate entity.
In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under
Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas.
The Bankruptcy Court entered an order confirming Mirants plan of reorganization in December 2005,
and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant
transferred substantially all of its assets and its restructured debt to a new corporation that
adopted the name Mirant Corporation (Reorganized Mirant).
Under the terms of the separation agreements entered into in connection with the spin-off, Mirant
agreed to indemnify Southern Company for certain costs. As a result of Mirants bankruptcy,
Southern Company sought reimbursement as an unsecured creditor in Mirants Chapter 11 proceeding.
If Southern Companys claims for indemnification with respect to these costs are allowed, then
Mirants indemnity obligations to Southern Company would constitute unsecured claims against Mirant
entitled to stock in Reorganized Mirant. As a result of the $202 million settlement on March 31,
2009 of another suit related to Mirant (MC Asset Recovery litigation), the maximum amount
Southern Company can assert by proof of claim in the Mirant bankruptcy is capped at $9.5 million.
See Note 5 under Effective Tax Rate for more information regarding the MC Asset Recovery
settlement. The final outcome of this matter cannot now be determined.
C-59
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Environmental Matters
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern
District of Georgia against certain Southern Company subsidiaries, including Alabama Power and
Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions
of the Clean Air Act and related state laws at certain coal-fired generating facilities. After
Alabama Power was dismissed from the original action, the EPA filed a separate action in January
2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In
these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating
facilities operated by Alabama Power and Georgia Power, including facilities co-owned by
Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief,
including an order requiring installation of the best available control technology at the affected
units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power
relating to Gulf Powers Plant Crist and Mississippi Powers Plant Watson. In early 2000, the EPA
filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based
on the allegations in the notices of violation. However, in March 2001, the court denied the
motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now
solely against Georgia Power, has been administratively closed since the spring of 2001, and the
case has not been reopened.
In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree
between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the
alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern
District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its
other affected units regarding the proper legal test for determining whether projects are routine
maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision
did not resolve the case, which remains ongoing.
Southern Company believes that the traditional operating companies complied with applicable laws
and the EPA regulations and interpretations in effect at the time the work in question took place.
The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation
at each generating unit, depending on the date of the alleged violation. An adverse outcome could
require substantial capital expenditures or affect the timing of currently budgeted capital
expenditures that cannot be determined at this time and could possibly require payment of
substantial penalties. Such expenditures could affect future results of operations, cash flows,
and financial condition if such costs are not recovered through regulated rates.
Carbon Dioxide Litigation
New York Case
In July 2004, three environmental groups and attorneys general from eight states, each outside of
Southern Companys service territory, and the corporation counsel for New York City filed
complaints in the U.S. District Court for the Southern District of New York against Southern
Company and four other electric power companies. The complaints allege that the companies
emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs
assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs
seek a judicial order (1) holding each defendant jointly and severally liable for creating,
contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap
its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year
for at least a decade. The plaintiffs have not, however, requested that damages be awarded in
connection with their claims. Southern Company believes these claims are without merit and notes
that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the
U.S. District Court for the Southern District of New York granted Southern Companys and the other
defendants motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of
Appeals for the Second Circuit in October 2005 and, on September 21, 2009, the U.S. Court of
Appeals for the Second Circuit reversed the district courts ruling, vacating the dismissal of the
plaintiffs claim, and remanding the case to the district court. On November 5, 2009, the
defendants, including Southern Company, sought rehearing en banc, and the courts ruling is subject
to potential appeal. Therefore, the ultimate outcome of these matters cannot be determined at this
time.
Kivalina Case
In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S.
District Court for the Northern District of California against several electric utilities
(including Southern Company), several oil companies, and a coal company. The plaintiffs are the
governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being
destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions
of greenhouse gases by the defendants. The plaintiffs assert claims for public and private
nuisance and contend that some of the defendants have acted in concert and are therefore jointly
C-60
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
and severally liable for the plaintiffs damages. The suit seeks damages for lost property values
and for the cost of relocating the village, which is alleged to be $95 million to $400 million.
Southern Company believes that these claims are without merit and notes that the complaint cites no
statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for
the Northern District of California granted the defendants motions to dismiss the case based on
lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the
plaintiffs failure to establish the standard for determining that the defendants conduct caused
the injury alleged. On November 5, 2009, the plaintiffs filed an appeal with the U.S. Court of
Appeals for the Ninth Circuit challenging the district courts order dismissing the case. The
ultimate outcome of this matter cannot be determined at this time.
Other Litigation
Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse
gas emissions have become more frequent, and courts have recently determined that private parties
and states have standing to bring such claims. For example, on October 16, 2009, the U.S. Court of
Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of
Mississippis dismissal of private party claims against certain oil, coal, chemical, and utility
companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S.
Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance,
trespass, and negligence claims and none of these claims are barred by the political question
doctrine. The Company is not currently a party to this litigation but the traditional operating
companies and Southern Power were named as defendants in an amended complaint which was rendered
moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such
court dismissed the original matter. The ultimate outcome of this matter cannot be determined at
this time.
Environmental Remediation
Southern Companys subsidiaries must comply with environmental laws and regulations that cover the
handling and disposal of waste and releases of hazardous substances. Under these various laws and
regulations, the subsidiaries may also incur substantial costs to clean up properties. The
traditional operating companies have each received authority from their respective state PSCs to
recover approved environmental compliance costs through regulatory mechanisms. Within limits
approved by the state PSCs, these rates are adjusted annually or as necessary.
Georgia Powers environmental remediation liability as of December 31, 2009 was $12.5 million.
Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive
Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in
Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the
removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of
natural resource damages at this site or for the assessment and potential cleanup of other sites on
the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.
By letter dated September 30, 2008, the EPA advised Georgia Power that it has been designated as a
PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other
entities have also received notices from the EPA. Georgia Power, along with other named PRPs, is
negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures
related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate
actions in the U.S. District Court for the Eastern District of North Carolina against numerous
other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred
by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of
these matters will depend upon further environmental assessment and the ultimate number of PRPs and
cannot be determined at this time; however, it is not expected to have a material impact on
Southern Companys financial statements.
Gulf Powers environmental remediation liability includes estimated costs of environmental
remediation projects of approximately $65.2 million as of December 31, 2009. These estimated costs
relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for
potential impacts to soil and groundwater from herbicide applications at Gulf Power substations.
The schedule for completion of the remediation projects will be subject to FDEP approval. The
projects have been approved by the Florida PSC for recovery through Gulf Powers environmental cost
recovery clause; therefore, there was no impact on net income as a result of these estimates.
The final outcome of these matters cannot now be determined. However, based on the currently known
conditions at these sites and the nature and extent of activities relating to these sites,
management does not believe that additional liabilities, if any, at these sites would be material
to the financial statements.
C-61
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
FERC Matters
Market-Based Rate Authority
Each of the traditional operating companies and Southern Power has authorization from the FERC to
sell power to non-affiliates, including short-term opportunity sales, at market-based prices.
Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
In December 2004, the FERC initiated a proceeding to assess Southern Companys generation market
power within its retail service territory. The ability to charge market-based rates in other
markets was not an issue in the proceeding. Any new market-based rate sales by any subsidiary of
Southern Company in Southern Companys retail service territory entered into during a 15-month
refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.
On December 23, 2009, Southern Company and the FERC trial staff reached an agreement in principle
that would resolve the proceeding in its entirety. The agreement does not reflect any finding or
suggestion that any subsidiary of Southern Company possesses or has exercised any market power.
The agreement likewise does not require Southern Company to make any refunds related to sales
during the 15-month refund period. The agreement does provide for the traditional operating
companies and Southern Power to donate a total of $1.7 million to nonprofit organizations in the
states in which they operate for the purpose of offsetting the electricity bills of low-income
retail customers. The agreement is subject to review and approval by the FERC.
Intercompany Interchange Contract
The Companys generation fleet in its retail service territory is operated under the Intercompany
Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new
proceeding to examine (1) the provisions of the IIC among the traditional operating companies,
Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is
operated, (2) whether any parties to the IIC have violated the FERCs standards of conduct
applicable to utility companies that are transmission providers, and (3) whether Southern Companys
code of conduct defining Southern Power as a system company rather than a marketing affiliate
is just and reasonable. In connection with the formation of Southern Power, the FERC authorized
Southern Powers inclusion in the IIC in 2000. The FERC also previously approved Southern
Companys code of conduct.
In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject
to Southern Companys agreement to accept certain modifications to the settlements terms.
Southern Company notified the FERC that it accepted the modifications. The modifications largely
involve functional separation and information restrictions related to marketing activities
conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a
compliance plan in connection with the order. In April 2007, the FERC approved, with certain
modifications, the plan submitted by Southern Company. Implementation of the plan did not have a
material impact on the Companys financial statements. In November 2007, Southern Company notified
the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued
for public comment its final audit report pertaining to compliance implementation and related
matters. No comments were submitted challenging the audit reports findings of Southern Companys
compliance. The proceeding remains open pending a decision from the FERC regarding the audit
report.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as
defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs lawsuits claim
that defendants may not use, or sublease to third parties, some or all of the fiber optic
communications lines on the rights of way that cross the plaintiffs properties and that such
actions exceed the easements or other property rights held by defendants. The plaintiffs assert
claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive
damages and injunctive relief. Management of Southern Company believes that its subsidiaries have
complied with applicable laws and that the plaintiffs claims are without merit.
To date, Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the
actions pending against Mississippi Power to clarify its easement rights in the State of
Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and
Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed.
These agreements have not resulted in any material effects on Southern Companys financial
statements.
C-62
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power,
were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by
Interstate Fibernet, Inc., a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses
certain of the defendants rights of way. This lawsuit alleges, among other things, that the
defendants are contractually obligated to indemnify, defend, and hold harmless the
telecommunications company from any liability that may be assessed against it in pending and future
right of way litigation. The Company believes that the plaintiffs claims are without merit. In
the fall of 2004, the trial court stayed the case until resolution of the underlying landowner
litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the
telecommunications companys appeal of the trial courts order for lack of jurisdiction. An
adverse outcome in this matter, combined with an adverse outcome against the telecommunications
company in one or more of the right of way lawsuits, could result in substantial judgments.
The final outcome of these matters cannot now be determined.
Nuclear Fuel Disposal Costs
Alabama Power and Georgia Power have contracts with the United States, acting through the U.S.
Department of Energy (DOE), which provide for the permanent disposal of spent nuclear fuel. The
DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and
Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of
contract.
In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million,
based on its ownership interests, and awarded Alabama Power approximately $17 million, representing
substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at
Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the governments motion
for reconsideration was denied. In January 2008, the government filed an appeal and, in February
2008, filed a motion to stay the appeal. In April 2008, the U.S. Court of Appeals for the Federal
Circuit granted the governments motion to stay the appeal pending the courts decisions in three
other similar cases already on appeal. Those cases were decided in August 2008. The U.S. Court of
Appeals for the Federal Circuit has left the stay of appeals in place pending the decision in an
appeal of another case involving spent nuclear fuel contracts.
In April 2008, a second claim against the government was filed for damages incurred after December
31, 2004 (the court-mandated cut-off in the original claim), due to the governments alleged
continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit
denied a similar request by the government to stay this proceeding. The complaint does not contain
any specific dollar amount for recovery of damages. Damages will continue to accumulate until the
issue is resolved or the storage is provided. No amounts have been recognized in the financial
statements as of December 31, 2009 for either claim. The final outcome of these matters cannot be
determined at this time, but no material impact on net income is expected as any damage amounts
collected from the government are expected to be returned to customers.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core
discharge capability for both units into 2014. Construction of an on-site dry storage facility at
Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge
capability. At Plants Hatch and Farley, on-site dry storage facilities are operational and can be
expanded to accommodate spent fuel through the expected life of each plant.
Income Tax Matters
Georgia Powers 2005 through 2008 income tax filings for the State of Georgia include state income
tax credits for increased activity through Georgia ports. Georgia Power has also filed similar
claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to
these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County
to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has
been recorded related to these credits. See Note 5 under Unrecognized Tax Benefits for
additional information. If Georgia Power prevails, these claims could have a significant, and
possibly material, positive effect on Southern Companys net income. If Georgia Power is not
successful, payment of the related state tax could have a significant, and possibly material,
negative effect on Southern Companys cash flow. The ultimate outcome of this matter cannot now be
determined.
C-63
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Retail Regulatory Matters
Alabama Power
Retail Rate Plans
Alabama Power operates under a Rate Stabilization and Equalization Plan (Rate RSE) approved by the
Alabama PSC. Rate RSE adjustments are based on forward-looking information for the applicable
upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot
exceed 4% per year and any annual adjustment is limited to 5%. Retail rates remain unchanged when
the retail return on common equity (ROE) is projected to be between 13% and 14.5%. If Alabama
Powers actual retail ROE is above the allowed equity return range, customer refunds will be
required; however, there is no provision for additional customer billings should the actual retail
ROE fall below the allowed equity return range. In October 2008, the Alabama PSC approved a
corrective rate package effective January 2009, that primarily provides for adjustments associated
with customer charges to certain existing rate structures. Alabama Power agreed to a moratorium on
any increase in rates in 2009 under Rate RSE. On December 1, 2009, Alabama Power made its Rate RSE
submission to the Alabama PSC of projected data for calendar year 2010. The Rate RSE increase for
2010 is 3.2%, or $152 million annually, and became effective in January 2010. The revenue
adjustment under the Rate RSE is largely attributable to the costs associated with fossil capacity
which is currently dedicated to certain long-term wholesale contracts that expire during 2010.
Retail cost of service for 2010 reflects the costs for that portion of the year in which this
capacity is no longer committed to wholesale. In an Alabama PSC order dated January 5, 2010, the
Alabama PSC acknowledged that a full calendar year of costs for such capacity would be reflected in
the Rate RSE calculation beginning in 2011 and thereafter. Under the terms of Rate RSE, the
maximum increase for 2011 cannot exceed 4.76%.
The Alabama PSC has also approved a rate mechanism that provides for adjustments to recognize the
cost of placing new generating facilities in retail service and for the recovery of retail costs
associated with certificated power purchase agreements (PPAs) under a Rate Certificated New Plant
(Rate CNP). There was no adjustment to Rate CNP in April 2007, 2008, or 2009. Effective April
2010, Rate CNP will be reduced approximately $70 million annually, primarily due to the expiration
on May 31, 2010 of the PPA with Southern Power covering the capacity of Plant Harris Unit 1. Rate
CNP also allows for the recovery of Alabama Powers retail costs associated with environmental
laws, regulations, or other such mandates. The rate mechanism is based on forward-looking
information and provides for the recovery of these costs pursuant to a factor that is calculated
annually. Environmental costs to be recovered include operations and maintenance expenses,
depreciation, and a return on invested capital. Retail rates increased approximately 2.4% in
January 2008 and 0.6% in January 2007 due to environmental costs. In October 2008, Alabama Power
agreed to defer collection during 2009 of any increase in rates under this portion of Rate CNP
which permits recovery of costs associated with environmental laws and regulations until 2010. The
deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had no
significant effect on Southern Companys revenues or net income in 2009. On December 1, 2009,
Alabama Power made its Rate CNP environmental submission to the Alabama PSC of projected data for
calendar year 2010. The Rate CNP environmental increase for 2010 is 4.3%, or $195 million
annually, based upon projected billings. Under the terms of the rate mechanism, the adjustment
became effective in January 2010. The Rate CNP environmental adjustment is primarily attributable
to scrubbers being placed in service during 2010 at four of Alabama Powers generating plants.
Fuel Cost Recovery
Alabama Power has established fuel cost recovery rates under an energy cost recovery clause (Rate
ECR) approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the
current over or under recovered balance. In June 2007, the Alabama PSC approved Alabama Powers
request to increase the retail energy cost recovery rate to 3.100 cents per kilowatt hour (KWH),
effective with billings beginning July 2007. In October 2008, the Alabama PSC approved an increase
in Alabama Powers Rate ECR factor to 3.983 cents per KWH effective with billings beginning October
2008. On June 2, 2009, the Alabama PSC approved a decrease in Alabama Powers Rate ECR factor to
3.733 cents per KWH for billings beginning June 9, 2009. On December 1, 2009, the Alabama PSC
approved a decrease in Alabama Powers Rate ECR factor to 2.731 cents per KWH for billings
beginning January 2010 through December 2011. The Alabama PSC further approved an additional
reduction in the Rate ECR factor of 0.328 cents per KWH for the billing months of January 2010
through December 2010 resulting in a Rate ECR factor of 2.403 cents per KWH for such 12-month
period. For billing months beginning January 2012, the Rate ECR factor shall be 5.910 cents per
KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial
statements, are adjusted for the difference in actual recoverable fuel costs and amounts billed in
current regulated rates. Accordingly, the approved decreases in the Rate ECR factor will have no
significant effect on Southern Companys net income, but will decrease operating cash flows related
to fuel cost recovery in 2010 when compared to 2009. As of December 31, 2009, Alabama Power had an
over recovered fuel balance of approximately $200 million, of which approximately $22 million is
included in other regulatory liabilities, deferred in the balance sheets. Alabama Power, along
with the Alabama PSC, will continue to monitor the over recovered fuel cost balance to determine
whether an additional adjustment to billing rates is required.
C-64
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Georgia Power
Retail Rate Plans
In December 2004, the Georgia PSC approved the 2004 Retail Rate Plan. Under the terms of the 2004
Retail Rate Plan, Georgia Powers earnings were evaluated against a retail ROE range of 10.25% to
12.25%. Two-thirds of any earnings above 12.25% were applied to rate refunds, with the remaining
one-third retained by Georgia Power. Retail rates and customer fees increased by approximately
$203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and
maintenance expenses, environmental compliance, and continued investment in new generation,
transmission, and distribution facilities to support growth and ensure reliability. In 2007,
Georgia Power refunded 2005 earnings above 12.25% retail ROE. There were no refunds related to
earnings for 2007.
In December 2007, the Georgia PSC approved the 2007 Retail Rate Plan. Under the 2007 Retail Rate
Plan, Georgia Powers earnings are evaluated against a retail ROE range of 10.25% to 12.25%.
Retail base rates increased by approximately $100 million effective January 1, 2008 to provide for
cost recovery of transmission, distribution, generation, and other investments, as well as
increased operating costs. In addition, the ECCR tariff was implemented to allow for the recovery
of costs related to environmental projects mandated by state and federal regulations. The ECCR
tariff increased rates by approximately $222 million effective January 1, 2008. In connection with
the 2007 Retail Rate Plan, Georgia Power agreed that it would not file for a general base rate
increase during this period unless its projected retail ROE falls below 10.25%. Georgia Power is
required to file a general rate case by July 1, 2010, in response to which the Georgia PSC would be
expected to determine whether the 2007 Retail Rate Plan should be continued, modified, or
discontinued.
Cost of Removal
The economic recession has significantly reduced Georgia Powers revenues upon which retail rates
were set under the 2007 Retail Rate Plan. In June 2009, despite stringent efforts to reduce
expenses, Georgia Powers projected retail ROE for both 2009 and 2010 was below 10.25%. However,
in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June
29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would
allow Georgia Power to amortize up to $324 million of its regulatory liability related to other
cost of removal obligations.
On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the
accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory
liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail
ROE. For the year ended December 31, 2009, Georgia Power amortized $41 million of the regulatory
liability. In addition, Georgia Power may amortize up to two-thirds of the regulatory liability
($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia
PSC approved increases in Georgia Powers total annual billings of approximately $383 million
effective March 1, 2007 and approximately $222 million effective June 1, 2008.
On December 15,
2009, Georgia Power filed for a fuel cost recovery increase with the
Georgia PSC. On February 22, 2010, Georgia Power, the Georgia PSC
Public Interest Advocacy Staff, and three customer groups entered into
a stipulation to resolve the case, subject to approval by the Georgia
PSC (the Stipulation). Under the terms of the Stipulation, Georgia
Powers annual fuel cost recovery billings will increase by
approximately $425 million. In addition, Georgia Power will implement
an interim fuel rider, which would allow Georgia Power to adjust its
fuel cost recovery rates prior to the next fuel case if the under
recovered fuel balance exceeds budget by more than $75 million.
Georgia Power is required to file its next fuel case by March 1, 2011.
The Georgia PSC is scheduled to vote on the Stipulation on March 11,
2010 with the new fuel rates to become effective April 1, 2010. The
ultimate outcome of this matter cannot be determined at this time.
As of
December 31, 2009, Georgia Powers under recovered fuel
balance totaled approximately $665
million, which if the Stipulation is approved, Georgia Power will
recover over 32 months beginning April 1, 2010. Therefore,
approximately $373 million of the under recovered regulatory clause revenues for
Georgia Power is included in deferred charges and other assets at December
31, 2009.
Fuel cost recovery revenues as recorded in the financial statements are adjusted for differences in
actual recoverable costs and amounts billed in current regulated rates. Accordingly, a change in
the billing factor has no significant effect on Southern Companys revenues or net income, but does
impact annual cash flow.
C-65
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Nuclear Construction
On August 26, 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern
Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation (OPC), the Municipal Electric
Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in
the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners
(collectively, Owners), related to two additional nuclear units on the site of Plant Vogtle (Plant
Vogtle Units 3 and 4). See Note 4 for additional information on these co-owners. In March 2008,
Southern Nuclear filed an application with the NRC for a combined construction and operating
license for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be
placed in service in 2016 and 2017, respectively.
In April 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium
consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc.
(collectively, Consortium) entered into an engineering, procurement, and construction agreement to
design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating
capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at
Plant Vogtle (Vogtle 3 and 4 Agreement).
The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the
entire facility with the exception of certain items provided by the Owners. Under the terms of the
Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that will be subject to certain
price escalations and adjustments, including certain index-based adjustments, as well as
adjustments for change orders, and performance bonuses for early completion and unit performance.
Each Owner is severally (and not jointly) liable for its proportionate share, based on its
ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement.
Georgia Powers proportionate share is 45.7%.
On
February 23, 2010, Georgia Power, acting for itself and as agent for the Owners, and the
Consortium entered into an amendment to the Vogtle 3 and 4 Agreement. The amendment, which is
subject to the approval of the Georgia PSC, replaces certain of the index-based adjustments to the
purchase price with fixed escalation amounts.
On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at
an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the
related construction work in progress accounts in rate base.
On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy
Financing Act that will allow Georgia Power to recover financing costs for nuclear construction
projects by including the related construction work in progress accounts in rate base during the
construction period. The cost recovery provisions will become effective on January 1, 2011. With
respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected
financing costs of approximately $1.7 billion during the construction period beginning in 2011,
which reduces the projected in-service cost to approximately $4.4 billion.
On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County,
Georgia seeking review of the Georgia PSCs certification order and challenging the
constitutionality of the Georgia Nuclear Energy Financing Act. Georgia Power believes there is no
meritorious basis for this petition and intends to vigorously defend against the requested actions.
On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to
certify the AP1000 standard design for new reactors and expressing concerns related to the
availability of adequate information and the shield building design. The shield building protects
the containment and provides structural support to the containment cooling water supply. Georgia
Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible
delays in the AP1000 design certification schedule, including those addressed by the NRC in their
letters, are not currently expected to affect the projected commercial operation dates for Plant
Vogtle Units 3 and 4.
There are pending technical and procedural challenges to the construction and licensing of Plant
Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as
construction proceeds.
On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction
monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not
include any proposed change to the estimated construction cost as certified by the Georgia PSC in
March 2009. On February 25, 2010, the Georgia PSC approved the expenditures made by Georgia Power
pursuant to the certification through June 30, 2009. The Georgia PSC also ordered that in its
future semi-annual construction monitoring reports, Georgia Power will report against a total
certified cost of approximately $6.1 billion, which is the effective certified amount after giving
effect to the Georgia Nuclear Energy Financing Act as described above. Georgia Power will continue
to file construction monitoring reports by February 28 and August 31 of each year during the
construction period.
The ultimate outcome of these matters cannot now be determined.
C-66
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Integrated Coal Gasification Combined Cycle (IGCC)
On January 16, 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity
with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper
County, Mississippi. The plant would utilize an advanced integrated coal gasification combined
cycle technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined
lignite from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the
Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper
IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain
regulatory approvals, is expected to begin commercial operation in May 2014. The Mississippi PSC
has issued orders allowing Mississippi Power to defer the costs associated with the generation
resource planning, evaluation, and screening activities as a regulatory asset. As of December 31,
2009, Mississippi Power had spent a total of $73.5 million of such costs including regulatory
filing costs.
On November 9, 2009, the Mississippi PSC issued an order that found Mississippi Power has a
demonstrated need for additional capacity. Hearings to determine the appropriate resource to fill
the need were held in February 2010 with a decision due by May 2010.
The ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and related facilities
jointly with Power South Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants
Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with OPC, MEAG Power, the City of
Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition,
Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with
Florida Power Corporation for a combustion turbine unit at Intercession City, Florida. Southern
Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the
Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.
At December 31, 2009, Alabama Powers, Georgia Powers, and Southern Powers ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the above entities were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
Amount of |
|
Accumulated |
|
|
Ownership |
|
Investment |
|
Depreciation |
|
|
|
|
|
|
(in millions) |
Plant Vogtle (nuclear)
Units 1 and 2 |
|
|
45.7 |
% |
|
$ |
3,285 |
|
|
$ |
1,916 |
|
Plant Hatch (nuclear) |
|
|
50.1 |
|
|
|
937 |
|
|
|
522 |
|
Plant Miller (coal)
Units 1 and 2 |
|
|
91.8 |
|
|
|
1,063 |
|
|
|
449 |
|
Plant Scherer (coal)
Units 1 and 2 |
|
|
8.4 |
|
|
|
133 |
|
|
|
70 |
|
Plant Wansley (coal) |
|
|
53.5 |
|
|
|
696 |
|
|
|
195 |
|
Rocky Mountain (pumped storage) |
|
|
25.4 |
|
|
|
175 |
|
|
|
106 |
|
Intercession City (combustion turbine) |
|
|
33.3 |
|
|
|
12 |
|
|
|
3 |
|
Plant Stanton (combined cycle)
Unit A |
|
|
65.0 |
|
|
|
151 |
|
|
|
20 |
|
|
At December 31, 2009, the portion of total construction work in progress related to Plants Miller,
Scherer, Wansley, and Vogtle Units 3 and 4 was $244 million, $247 million, $5 million, and $611
million, respectively. Construction at Plants Miller, Wansley, and Scherer relates primarily to
environmental projects. See Note 3 under Retail Regulatory Matters Georgia Power Nuclear
Construction for information on Plant Vogtle Units 3 and 4.
Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the
jointly owned facilities, except for Rocky Mountain and Intercession City, as agents for their
respective co-owners. The companies proportionate share of their plant operating expenses is
included in the corresponding operating expenses in the statements of income and each company is
responsible for providing its own financing.
C-67
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and combined state income tax
returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax
allocation agreement, each subsidiarys current and deferred tax expense is computed on a
stand-alone basis. In accordance with IRS regulations, each company is jointly and severally
liable for the tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
$ |
771 |
|
|
$ |
628 |
|
|
$ |
715 |
|
Deferred |
|
|
40 |
|
|
|
177 |
|
|
|
11 |
|
|
|
|
|
811 |
|
|
|
805 |
|
|
|
726 |
|
|
State |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
100 |
|
|
|
72 |
|
|
|
114 |
|
Deferred |
|
|
(15 |
) |
|
|
38 |
|
|
|
(5 |
) |
|
|
|
|
85 |
|
|
|
110 |
|
|
|
109 |
|
|
Total |
|
$ |
896 |
|
|
$ |
915 |
|
|
$ |
835 |
|
|
Net cash payments for income taxes in 2009, 2008, and 2007 were $975 million, $537 million, and
$732 million, respectively.
The tax effects of temporary differences between the carrying amounts of assets and liabilities in
the financial statements and their respective tax bases, which give rise to deferred tax assets and
liabilities, are as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
Deferred tax
liabilities |
|
|
|
|
|
|
|
|
Accelerated depreciation |
|
$ |
5,938 |
|
|
$ |
5,356 |
|
Property basis differences |
|
|
986 |
|
|
|
968 |
|
Leveraged lease basis differences |
|
|
251 |
|
|
|
306 |
|
Employee benefit obligations |
|
|
384 |
|
|
|
364 |
|
Under recovered fuel clause |
|
|
271 |
|
|
|
516 |
|
Premium on reacquired debt |
|
|
100 |
|
|
|
107 |
|
Regulatory assets associated with employee benefit obligations |
|
|
939 |
|
|
|
869 |
|
Regulatory assets associated with asset retirement obligations |
|
|
486 |
|
|
|
480 |
|
Other |
|
|
216 |
|
|
|
132 |
|
|
Total |
|
|
9,571 |
|
|
|
9,098 |
|
|
Deferred tax
assets |
|
|
|
|
|
|
|
|
Federal effect of state deferred taxes |
|
|
302 |
|
|
|
354 |
|
State effect of federal deferred taxes |
|
|
108 |
|
|
|
105 |
|
Employee benefit obligations |
|
|
1,435 |
|
|
|
1,325 |
|
Over recovered fuel clause |
|
|
119 |
|
|
|
|
|
Other property basis differences |
|
|
132 |
|
|
|
144 |
|
Deferred costs |
|
|
65 |
|
|
|
99 |
|
Cost of removal |
|
|
109 |
|
|
|
|
|
Unbilled revenue |
|
|
96 |
|
|
|
100 |
|
Other comprehensive losses |
|
|
81 |
|
|
|
82 |
|
Asset retirement obligations |
|
|
486 |
|
|
|
480 |
|
Other |
|
|
458 |
|
|
|
279 |
|
|
Total |
|
|
3,391 |
|
|
|
2,968 |
|
|
Total deferred tax liabilities, net |
|
|
6,180 |
|
|
|
6,130 |
|
Portion included in prepaid expenses (accrued income taxes), net |
|
|
229 |
|
|
|
(90 |
) |
Deferred state tax assets |
|
|
105 |
|
|
|
103 |
|
Valuation allowance |
|
|
(59 |
) |
|
|
(63 |
) |
|
Accumulated deferred income taxes |
|
$ |
6,455 |
|
|
$ |
6,080 |
|
|
C-68
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
At December 31, 2009, Southern Company had a State of Georgia net operating loss (NOL)
carryforward totaling $1.0 billion, which could result in net state income tax benefits of $55
million, if utilized. However, Southern Company has established a valuation allowance for the
potential $55 million tax benefit due to the remote likelihood that the tax benefit will be
realized. These NOLs expire between 2010 and 2021. During 2009, Southern Company utilized
$4 million in available NOLs, which resulted in a $0.2 million state income tax benefit. The State
of Georgia allows the filing of a combined return, which should substantially reduce any additional
NOL carryforwards.
At December 31, 2009, the tax-related regulatory assets and liabilities were $1.05 billion and
$249 million, respectively. These assets are attributable to tax benefits flowed through to
customers in prior years and to taxes applicable to capitalized interest. These liabilities are
attributable to deferred taxes previously recognized at rates higher than the current enacted tax
law and to unamortized investment tax credits.
Effective Tax Rate
The provision for income taxes differs from the amount of income taxes determined by applying the
applicable U.S. federal statutory rate to earnings before income taxes and preferred and preference
dividends of subsidiaries, as a result of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
Federal statutory rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
State income tax, net of federal deduction |
|
|
2.1 |
|
|
|
2.6 |
|
|
|
2.7 |
|
Synthetic fuel tax credits |
|
|
|
|
|
|
|
|
|
|
(1.4 |
) |
Employee stock plans dividend deduction |
|
|
(1.4 |
) |
|
|
(1.3 |
) |
|
|
(1.3 |
) |
Non-deductible book depreciation |
|
|
0.9 |
|
|
|
0.8 |
|
|
|
0.9 |
|
Difference in prior years deferred and current tax rate |
|
|
(0.1 |
) |
|
|
(0.2 |
) |
|
|
(0.2 |
) |
AFUDC-Equity |
|
|
(2.7 |
) |
|
|
(1.9 |
) |
|
|
(1.4 |
) |
Production activities deduction |
|
|
(0.7 |
) |
|
|
(0.4 |
) |
|
|
(0.8 |
) |
Leveraged lease termination |
|
|
(0.9 |
) |
|
|
|
|
|
|
|
|
MC Asset Recovery |
|
|
2.7 |
|
|
|
|
|
|
|
|
|
Donations |
|
|
(0.4 |
) |
|
|
|
|
|
|
(0.8 |
) |
Other |
|
|
(0.1 |
) |
|
|
(1.0 |
) |
|
|
(0.8 |
) |
|
Effective income tax rate |
|
|
34.4 |
% |
|
|
33.6 |
% |
|
|
31.9 |
% |
|
Southern Companys 2009 effective tax rate increased from 2008 primarily due to the $202 million
charge recorded for the MC Asset Recovery litigation settlement, which completed and resolved all
claims by MC Asset Recovery against Southern Company. Southern Company is currently evaluating
potential recovery of the settlement payment through various means. The degree to which any
recovery is realized will determine, in part, the final income tax treatment of the settlement
payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be
determined at this time. The increase in Southern Companys effective tax rate was partially
offset by the gain on the early termination of an international leveraged lease investment and the
increase in AFUDC related to increased construction expenditures.
The American Jobs Creation Act of 2004 created a tax deduction for a portion of income attributable
to U. S. production activities as defined in the Internal Revenue Code Section 199 (production
activities deduction). The deduction is equal to a stated percentage of qualified production
activities net income. The percentage is phased in over the years 2005 through 2010 with a 3% rate
applicable to the years 2005 and 2006, a 6% rate applicable for the years 2007 through 2009, and a
9% rate thereafter. The IRS has not clearly defined a methodology for calculating this deduction.
However, Southern Company reached an agreement with the IRS on a calculation methodology and signed
a closing agreement in December 2008. Therefore, in 2008, Southern Company reversed the
unrecognized tax benefit related to the calculation methodology and adjusted the deduction for all
previous years to conform to the agreement which resulted in a decrease in the 2008 deduction when
compared to the 2007 deduction. Certain aspects of the production activities deduction remain
unresolved. The net impact of the reversal of the unrecognized tax benefits combined with the
application of the new methodology had no material effect on the Companys financial statements.
For 2009, Georgia Power donated 5,111 acres of land to the State of Georgia. In 2007, Georgia
Power donated 2,200 acres of land in the Tallulah Gorge State Park to the State of Georgia. The
estimated value of the donations lowered the effective income tax rate for the years ended December
31, 2009 and December 31, 2007.
C-69
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Unrecognized Tax Benefits
For 2009, the total amount of unrecognized tax benefits increased by $53 million, resulting in a
balance of $199 million as of December 31, 2009.
Changes during the year in unrecognized tax benefits were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
|
Unrecognized tax benefits at beginning of year |
|
$ |
146 |
|
|
$ |
264 |
|
|
$ |
211 |
|
Tax positions from current periods |
|
|
53 |
|
|
|
49 |
|
|
|
46 |
|
Tax positions from prior periods |
|
|
2 |
|
|
|
130 |
|
|
|
7 |
|
Reductions due to settlements |
|
|
|
|
|
|
(297 |
) |
|
|
|
|
Reductions due to expired statute of limitations |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
$ |
199 |
|
|
$ |
146 |
|
|
$ |
264 |
|
|
The tax positions from current periods increase for 2009 relate primarily to the Georgia state tax
credits litigation, the production activities deduction tax position, and other miscellaneous
uncertain tax positions. The tax positions increase from prior
periods for 2009 relates primarily to the
production activities deduction tax position. See Note 3 under Income Tax Matters for additional
information.
Impact on Southern Companys effective tax rate, if recognized, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
|
Tax positions impacting the effective tax rate |
|
$ |
199 |
|
|
$ |
143 |
|
|
$ |
96 |
|
Tax positions not impacting the effective tax rate |
|
|
|
|
|
|
3 |
|
|
|
168 |
|
|
Balance of unrecognized tax benefits |
|
$ |
199 |
|
|
$ |
146 |
|
|
$ |
264 |
|
|
The tax positions impacting the effective tax rate primarily relate to
Georgia state tax credit litigation at Georgia Power and the production activities deduction tax
position. See Note 3 under Income Tax Matters for additional information.
Accrued interest for unrecognized tax benefits was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
|
Interest accrued at beginning of year |
|
$ |
15 |
|
|
$ |
31 |
|
|
$ |
27 |
|
Interest reclassified due to settlements |
|
|
|
|
|
|
(49 |
) |
|
|
|
|
Interest accrued during the year |
|
|
6 |
|
|
|
33 |
|
|
|
4 |
|
|
Balance at end of year |
|
$ |
21 |
|
|
$ |
15 |
|
|
$ |
31 |
|
|
Southern Company classifies interest on tax uncertainties as interest expense. The net amount of
interest accrued during 2009 was primarily associated with the Georgia state tax credit
litigation.
Southern Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of
Southern Companys unrecognized tax positions will significantly increase or decrease within the
next 12 months. The possible settlement of the Georgia state tax credits litigation and/or the
conclusion or settlement of state audits could impact the balances significantly. At this time, an
estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has audited and closed all tax returns prior to 2004. The audits for the state returns
have either been concluded, or the statute of limitations has expired, for years prior to 2006.
C-70
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
6. FINANCING
Long-Term Debt Payable to Affiliated Trusts
Certain of the traditional operating companies have formed certain wholly-owned trust subsidiaries
for the purpose of issuing preferred securities. The proceeds of the related equity investments
and preferred security sales were loaned back to the applicable traditional operating company
through the issuance of junior subordinated notes totaling $412 million, which constitute
substantially all of the assets of these trusts and are reflected in the balance sheets as
Long-term Debt. Such traditional operating companies each consider that the mechanisms and
obligations relating to the preferred securities issued for its benefit, taken together, constitute
a full and unconditional guarantee by it of the respective trusts payment obligations with respect
to these securities. At December 31, 2009, preferred securities of $400 million were outstanding.
See Note 1 under Variable Interest Entities for additional information on the accounting
treatment for these trusts and the related securities.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31
was as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(in millions) |
|
Capitalized leases |
|
$ |
21 |
|
|
$ |
20 |
|
Senior notes |
|
|
1,090 |
|
|
|
565 |
|
Other long-term debt |
|
|
2 |
|
|
|
32 |
|
|
Total |
|
$ |
1,113 |
|
|
$ |
617 |
|
|
Maturities through 2014 applicable to total long-term debt are as follows: $1.1 billion in 2010;
$1.1 billion in 2011; $1.8 billion in 2012; $941 million in 2013; and $430 million in 2014.
Bank Term Loans
Certain of the traditional operating companies have entered into bank term loan agreements. In
2008, Georgia Power borrowed $300 million under a three-year term loan agreement. In 2008, Gulf
Power borrowed $110 million under a three-year loan agreement. Mississippi Power also borrowed
$80 million under a three-year term loan agreement in 2008. The proceeds of these loans were used
to repay maturing long-term and short-term indebtedness and for other general corporate purposes.
Senior Notes
Southern Company and its subsidiaries issued a total of $2.4 billion of senior notes in 2009.
Southern Company issued $650 million, and the traditional operating companies combined issuances
totaled $1.8 billion. The proceeds of these issuances were used to repay long-term and short-term
indebtedness and for other general corporate purposes.
At December 31, 2009 and 2008, Southern Company and its subsidiaries had a total of $14.7 billion
and $12.9 billion, respectively, of senior notes outstanding. At December 31, 2009 and 2008,
Southern Company had a total of $1.8 billion and $1.1 billion, respectively, of senior notes
outstanding.
Pollution Control Revenue Bonds
Pollution control obligations represent loans to the traditional operating companies from public
authorities of funds derived from sales by such authorities of revenue bonds issued to finance
pollution control and solid waste disposal facilities. The traditional operating companies have
$3.6 billion of outstanding pollution control revenue bonds and are required to make payments
sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds
from certain issuances are restricted until qualifying expenditures are incurred.
C-71
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
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. Alabama Power and Gulf Power have granted one or more
liens on certain of their respective property in connection with the issuance of certain pollution
control revenue bonds with an outstanding principal amount of $194 million. There are no
agreements or other arrangements among the subsidiary companies under which the assets of one
company have been pledged or otherwise made available to satisfy obligations of Southern Company or
any of its other subsidiaries.
Bank Credit Arrangements
At December 31, 2009, unused credit arrangements with banks totaled $4.8 billion, of which $1.5
billion expires during 2010, $25 million expires in 2011, and $3.2 billion expires in 2012. The
following table outlines the credit arrangements by company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executable |
|
|
|
|
|
|
|
|
|
|
|
|
Term-Loans |
|
Expires |
|
|
|
|
|
|
|
|
|
|
One |
|
Two |
|
|
|
|
|
|
Company |
|
Total |
|
Unused |
|
Year |
|
Years |
|
2010 |
|
2011 |
|
2012 |
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
Southern Company |
|
$ |
950 |
|
|
$ |
950 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
950 |
|
Alabama Power |
|
|
1,271 |
|
|
|
1,271 |
|
|
|
372 |
|
|
|
|
|
|
|
481 |
|
|
|
25 |
|
|
|
765 |
|
Georgia Power |
|
|
1,715 |
|
|
|
1,703 |
|
|
|
|
|
|
|
40 |
|
|
|
595 |
|
|
|
|
|
|
|
1,120 |
|
Gulf Power |
|
|
220 |
|
|
|
220 |
|
|
|
70 |
|
|
|
|
|
|
|
220 |
|
|
|
|
|
|
|
|
|
Mississippi Power |
|
|
156 |
|
|
|
156 |
|
|
|
15 |
|
|
|
41 |
|
|
|
156 |
|
|
|
|
|
|
|
|
|
Southern Power |
|
|
400 |
|
|
|
400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
400 |
|
Other |
|
|
60 |
|
|
|
60 |
|
|
|
60 |
|
|
|
|
|
|
|
60 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4,772 |
|
|
$ |
4,760 |
|
|
$ |
517 |
|
|
$ |
81 |
|
|
$ |
1,512 |
|
|
$ |
25 |
|
|
$ |
3,235 |
|
|
All of the credit arrangements require payment of commitment fees based on the unused portion of
the commitments or the maintenance of compensating balances with the banks. Commitment fees
average approximately 1/2 of 1% or less for Southern Company, the traditional operating companies,
and Southern Power. Compensating balances are not legally restricted from withdrawal.
Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total
capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the
long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities.
At December 31, 2009, Southern Company, Southern Power, and the traditional operating companies
were each in compliance with their respective debt limit covenants.
In addition, the credit arrangements typically contain cross default provisions that would be
triggered if the borrower defaulted on other indebtedness above a specified threshold. The cross
default provisions are restricted only to the indebtedness, including any guarantee obligations, of
the company that has such credit arrangements. Southern Company and its subsidiaries are currently
in compliance with all such covenants.
A portion of the $4.8 billion unused credit with banks is allocated to provide liquidity support to
the traditional operating companies variable rate pollution control revenue bonds. The amount of
variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2009
was approximately $1.6 billion. Subsequent to December 31, 2009, two remarketings of pollution
control revenue bonds increased the total requiring liquidity support to $1.8 billion.
Southern Company, the traditional operating companies, and Southern Power make short-term
borrowings primarily through commercial paper programs that have the liquidity support of committed
bank credit arrangements. Southern Company and the traditional operating companies may also borrow
through various other arrangements with banks. The amounts of commercial paper outstanding and
included in notes payable in the balance sheets at December 31, 2009 and December 31, 2008 were
$638 million and $794 million, respectively. The amounts of short-term bank loans included in
notes payable in the balance sheets at December 31, 2008 were $150 million. There were no short
term-bank loans included in notes payable in the balance sheet at December 31, 2009.
During 2009, the peak amount outstanding for short-term debt was $1.4 billion, and the average
amount outstanding was $956 million. The average annual interest rate on short-term debt was 0.4%
for 2009 and 2.7% for 2008.
C-72
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Changes in Redeemable Preferred Stock of Subsidiaries
Each of the traditional operating companies has issued preferred and/or preference stock. The
preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders
to elect a majority of such subsidiarys board of directors if dividends are not paid for four
consecutive quarters. Because such a potential redemption-triggering event is not solely within
the control of Alabama Power and Mississippi Power, this preferred stock is presented as
Redeemable Preferred Stock of Subsidiaries in a manner consistent with temporary equity under
applicable accounting standards. The preferred and preference stock at Georgia Power and the
preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow
the holders to elect a majority of such subsidiarys board. As a result, under applicable
accounting standards, the preferred and preference stock at Georgia Power and the preference stock
at Alabama Power and Gulf Power are required to be shown as noncontrolling interest, separately
presented as a component of Stockholders Equity on Southern Companys consolidated balance
sheets, consolidated statements of capitalization, and consolidated statements of stockholders
equity.
The following table presents changes during the year in redeemable preferred stock of subsidiaries
for Southern Company:
|
|
|
|
|
|
|
Redeemable Preferred Stock |
|
|
of Subsidiaries |
|
|
(in millions) |
Balance at December 31, 2006 |
|
$ |
498 |
|
Issued |
|
|
|
|
Redeemed |
|
|
|
|
|
Balance at December 31, 2007 |
|
$ |
498 |
|
Issued |
|
|
|
|
Redeemed |
|
|
(125 |
) |
Other |
|
|
2 |
|
|
Balance at December 31, 2008 |
|
$ |
375 |
|
Issued |
|
|
|
|
Redeemed |
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
375 |
|
|
7. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently estimated to total $4.9
billion in 2010, $5.3 billion in 2011, and $6.2 billion in 2012. These amounts include $271
million, $157 million, and $166 million in 2010, 2011, and 2012, respectively, for construction
expenditures related to contractual purchase commitments for nuclear fuel included herein under
Fuel and Purchased Power Commitments. The construction programs are subject to periodic review
and revision, and actual construction costs may vary from these estimates because of numerous
factors. These factors include: changes in business conditions; changes in load projections;
changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory
requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the
cost and efficiency of construction labor, equipment, and materials; project scope and design
changes; and the cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered. At December 31, 2009, significant purchase
commitments were outstanding in connection with the ongoing construction program, which includes
new facilities and capital improvements to transmission, distribution, and generation facilities,
including those to meet environmental standards. See Note 3 under Retail Regulatory Matters
Georgia Power Nuclear Construction and Retail Regulatory Matters Integrated Coal Gasification
Combined Cycle for additional information.
Long-Term Service Agreements
The traditional operating companies and Southern Power have entered into Long-Term Service
Agreements (LTSAs) with General Electric (GE), Alstom Power, Inc., Mitsubishi Power Systems
Americas, Inc., and Siemens AG for the purpose of securing maintenance support for the combined
cycle and combustion turbine generating facilities owned or under construction by the subsidiaries.
The LTSAs cover all planned inspections on the covered equipment, which generally includes the
cost of all labor and materials. The LTSAs are also obligated to cover the costs of unplanned
maintenance on the covered equipment subject to limits and scope specified in each contract.
C-73
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled
payments under the LTSAs, which are subject to price escalation, are made at various intervals
based on actual operating hours or number of gas turbine starts of the respective units. Total
remaining payments under these agreements for facilities owned are currently estimated at
$2.4 billion over the remaining life of the agreements, which are currently estimated to range up
to 24 years. However, the LTSAs contain various cancellation provisions at the option of the
purchasers.
Georgia Power has also entered into an LTSA with GE through 2014 for neutron monitoring system
parts and electronics at Plant Hatch. Total remaining payments to GE under this agreement are
currently estimated at $8 million. The contract contains cancellation provisions at the option of
Georgia Power.
Payments made under the LTSAs prior to the performance of any work are recorded as a prepayment in
the balance sheets. All work performed is capitalized or charged to expense (net of any joint
owner billings), as appropriate based on the nature of the work.
Limestone Commitments
As part of Southern Companys program to reduce sulfur dioxide emissions from its coal plants, the
traditional operating companies have entered into various long-term commitments for the procurement
of limestone to be used in flue gas desulfurization equipment. Limestone contracts are structured
with tonnage minimums and maximums in order to account for fluctuations in coal burn and sulfur
content. Southern Company has a minimum contractual obligation of 7.0 million tons, equating to
approximately $295 million, through 2019. Estimated expenditures (based on minimum contracted
obligated dollars) over the next five years are $37 million in 2010, $36 million in 2011, $37
million in 2012, $38 million in 2013, and $39 million in 2014.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, Southern Company has entered
into various long-term commitments for the procurement of fossil, biomass fuel, and nuclear fuel.
In most cases, these contracts contain provisions for price escalations, minimum purchase levels,
and other financial commitments. Coal commitments include forward contract purchases for sulfur
dioxide and nitrogen oxide emissions allowances. Natural gas purchase commitments contain fixed
volumes with prices based on various indices at the time of delivery; amounts included in the chart
below represent estimates based on New York Mercantile Exchange future prices at December 31, 2009.
Also, Southern Company has entered into various long-term commitments for the purchase of capacity
and electricity. Total estimated minimum long-term obligations at December 31, 2009 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments |
|
|
Natural Gas |
|
Coal |
|
Nuclear Fuel |
|
Biomass Fuel |
|
Purchased Power* |
|
|
(in millions) |
|
2010 |
|
$ |
1,349 |
|
|
$ |
4,490 |
|
|
$ |
271 |
|
|
$ |
|
|
|
$ |
253 |
|
2011 |
|
|
1,266 |
|
|
|
3,135 |
|
|
|
157 |
|
|
|
|
|
|
|
258 |
|
2012 |
|
|
926 |
|
|
|
1,572 |
|
|
|
166 |
|
|
|
17 |
|
|
|
266 |
|
2013 |
|
|
816 |
|
|
|
1,063 |
|
|
|
148 |
|
|
|
17 |
|
|
|
235 |
|
2014 |
|
|
688 |
|
|
|
850 |
|
|
|
83 |
|
|
|
18 |
|
|
|
267 |
|
2015 and thereafter |
|
|
4,153 |
|
|
|
2,508 |
|
|
|
297 |
|
|
|
128 |
|
|
|
2,742 |
|
|
Total |
|
$ |
9,198 |
|
|
$ |
13,618 |
|
|
$ |
1,122 |
|
|
$ |
180 |
|
|
$ |
4,021 |
|
|
|
|
|
* |
|
Certain PPAs reflected in the table are accounted for as
operating leases. |
Additional commitments for fuel will be required to supply Southern Companys future
needs. Total charges for nuclear fuel included in fuel expense amounted to $160 million
in 2009, $147 million in 2008, and $144 million in 2007.
Operating Leases
In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle
generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating
facility was acquired by Juniper Capital L.P. (Juniper), whose partners are unaffiliated with
Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with
Mississippi Power. Juniper has also entered into leases with other parties unrelated to
Mississippi Power. The assets leased by Mississippi Power comprise less than 50% of Junipers
assets. Mississippi Power is not required to consolidate the leased assets and related
liabilities, and the lease with Juniper is considered an operating lease. The initial lease term
ends in 2011, and the lease includes a purchase and
C-74
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
renewal option based on the cost of the facility at the inception of the lease. Mississippi Power
is required to amortize approximately 4% of the initial acquisition cost over the initial lease
term. In April 2010, 18 months prior to the end of the initial lease term, Mississippi Power must
notify Juniper if the lease will be terminated. Mississippi Power may elect to renew the lease for
10 years. If the lease is renewed, the agreement calls for Mississippi Power to amortize an
additional 17% of the initial completion cost over the renewal period. Upon termination of the
lease, at Mississippi Powers option, it may either exercise its purchase option or the facility
can be sold to a third party. If Mississippi Power does not exercise either its purchase option or
its renewal option, Mississippi Power could lose its rights to some or all of the 1,064 MWs of
capacity at that time.
The lease provides for a residual value guarantee, approximately 73% of the acquisition cost, by
Mississippi Power that is due upon termination of the lease in the event that Mississippi Power
does not renew the lease or purchase the assets and that the fair market value is less than the
unamortized cost of the asset. A liability of approximately $3 million, $5 million, and $7 million
for the fair market value of this residual value guarantee is included in the balance sheets as of
December 31, 2009, 2008, and 2007, respectively.
Southern Company also has other operating lease agreements with various terms and expiration dates.
Total operating lease expenses were $186 million, $184 million, and $187 million for 2009, 2008,
and 2007, respectively. Southern Company includes any step rents, escalations, and lease
concessions in its computation of minimum lease payments, which are recognized on a straight-line
basis over the minimum lease term.
At December 31, 2009, estimated minimum lease payments for noncancelable operating leases were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum Lease Payments |
|
|
Plant Daniel |
|
Barges & Rail Cars |
|
Other |
|
Total |
|
|
(in millions) |
2010 |
|
$ |
28 |
|
|
$ |
70 |
|
|
$ |
46 |
|
|
$ |
144 |
|
2011 |
|
|
28 |
|
|
|
57 |
|
|
|
38 |
|
|
|
123 |
|
2012 |
|
|
|
|
|
|
40 |
|
|
|
29 |
|
|
|
69 |
|
2013 |
|
|
|
|
|
|
32 |
|
|
|
22 |
|
|
|
54 |
|
2014 |
|
|
|
|
|
|
27 |
|
|
|
18 |
|
|
|
45 |
|
2015 and thereafter |
|
|
|
|
|
|
28 |
|
|
|
96 |
|
|
|
124 |
|
|
Total |
|
$ |
56 |
|
|
$ |
254 |
|
|
$ |
249 |
|
|
$ |
559 |
|
|
For the traditional operating companies, a majority of the barge and rail car lease expenses are
recoverable through fuel cost recovery provisions. In addition to the above rental commitments,
Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to
the residual value of the leased property. These leases expire in 2010, 2011, and 2013, and the
maximum obligations are $61 million, $40 million, and $19 million, respectively. At the
termination of the leases, the lessee may either exercise its purchase option, or the property can
be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the
leased property would substantially reduce or eliminate the payments under the residual value
obligations. However, due to the recessionary economy, it is possible that the fair market value
of the leased property would not eliminate the payments under the residual value obligations on the
leases expiring in 2010.
Guarantees
As discussed earlier in this Note under Operating Leases, Alabama Power, Georgia Power, and
Mississippi Power have entered into certain residual value guarantees.
8. COMMON STOCK
Stock Issued
In 2009, Southern Company issued 22.6 million shares of common stock for $673 million through the
Southern Investment Plan and employee and director stock plans. In addition, Southern Company
issued 19.9 million shares of common stock through at-the-market issuances pursuant to sales agency
agreements related to Southern Companys continuous equity offering program and received cash
proceeds of $613 million, net of $6 million in fees and commissions. In 2008, Southern Company
raised $474 million from the issuance of 14.1 million new common shares through the Southern
Investment Plan and employee and director stock plans.
C-75
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Shares Reserved
At December 31, 2009, a total of 91 million shares were reserved for issuance pursuant to the
Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the
Omnibus Incentive Compensation Plan (which includes the stock option plan discussed below).
Stock Option Plan
Southern Company provides non-qualified stock options to a large segment of its employees ranging
from line management to executives. As of December 31, 2009, there were 7,563 current and former
employees participating in the stock option plan, and there were 21 million shares of common stock
remaining available for awards under this plan. The prices of options granted to date have been at
the fair market value of the shares on the dates of grant. Options granted to date become
exercisable pro rata over a maximum period of three years from the date of grant. Southern Company
generally recognizes stock option expense on a straight-line basis over the vesting period which
equates to the requisite service period; however, for employees who are eligible for retirement,
the total cost is expensed at the grant date. Options outstanding will expire no later than
10 years after the date of grant, unless terminated earlier by the Southern Company Board of
Directors in accordance with the stock option plan. For certain stock option awards, a change in
control will provide accelerated vesting.
The estimated fair values of stock options granted in 2009, 2008, and 2007 were derived using the
Black-Scholes stock option pricing model. Expected volatility was based on historical volatility
of Southern 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 |
|
2009 |
|
2008 |
|
2007 |
|
Expected volatility |
|
|
15.6 |
% |
|
|
13.1 |
% |
|
|
14.8 |
% |
Expected term (in years) |
|
|
5.0 |
|
|
|
5.0 |
|
|
|
5.0 |
|
Interest rate |
|
|
1.9 |
% |
|
|
2.8 |
% |
|
|
4.6 |
% |
Dividend yield |
|
|
5.4 |
% |
|
|
4.5 |
% |
|
|
4.3 |
% |
Weighted
average grant-date fair value |
|
$1.80 |
|
$ |
2.37 |
|
|
$ |
4.12 |
|
Southern Companys activity in the stock option plan for 2009 is summarized below:
|
|
|
|
|
|
|
|
|
|
|
Shares Subject |
|
Weighted Average |
|
|
To Option |
|
Exercise Price |
|
Outstanding at December 31, 2008 |
|
|
36,941,273 |
|
|
$ |
32.09 |
|
Granted |
|
|
12,292,239 |
|
|
|
31.38 |
|
Exercised |
|
|
(879,555 |
) |
|
|
21.97 |
|
Cancelled |
|
|
(106,638 |
) |
|
|
32.48 |
|
|
Outstanding at December 31, 2009 |
|
|
48,247,319 |
|
|
$ |
32.10 |
|
|
Exercisable at December 31, 2009 |
|
|
30,209,272 |
|
|
$ |
31.57 |
|
|
The number of stock options vested, and expected to vest in the future, as of December 31, 2009 was
not significantly different from the number of stock options outstanding at December 31, 2009 as
stated above. As of December 31, 2009, the weighted average remaining contractual term for the
options outstanding and options exercisable was 6 years and 5 years, respectively, and the
aggregate intrinsic value for the options outstanding and options exercisable was $100 million and
$77 million, respectively.
As of December 31, 2009, there was $6 million of total unrecognized compensation cost related to
stock option awards not yet vested. That cost is expected to be recognized over a weighted-average
period of approximately 10 months.
For the years ended December 31, 2009, 2008, and 2007, total compensation cost for stock option
awards recognized in income was $23 million, $20 million, and $28 million, respectively, with the
related tax benefit also recognized in income of $9 million, $8 million, and $11 million,
respectively.
C-76
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and
2007 was $9 million, $45 million, and $81 million, respectively. The actual tax benefit realized
by the Company for the tax deductions from stock option exercises totaled $4 million, $17 million,
and $31 million, respectively, for the years ended December 31, 2009, 2008, and 2007.
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received
from issuances related to option exercises under the share-based payment arrangements for the years
ended December 31, 2009, 2008, and 2007 was $19 million, $113 million, and $195 million,
respectively.
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is
attributable to outstanding options under the stock option plan. The effect of the stock options
was determined using the treasury stock method. Shares used to compute diluted earnings per share
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Common Stock Shares |
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in thousands) |
|
As reported shares |
|
|
794,795 |
|
|
|
771,039 |
|
|
|
756,350 |
|
Effect of options |
|
|
1,620 |
|
|
|
3,809 |
|
|
|
4,666 |
|
|
Diluted shares |
|
|
796,415 |
|
|
|
774,848 |
|
|
|
761,016 |
|
|
The reduction in the effect of options for the years ended December 31, 2009 and 2008 compared to
2007 is primarily due to the anti-dilutive nature of certain stock options outstanding that have an
exercise price that exceeds the average stock price of Southern Company shares in the year ended
December 31, 2009 and 2008, respectively. At December 31, 2009 and 2008, there were 37.7 million
and 6.8 million stock options outstanding, respectively, that were not included in the diluted
earnings per share calculation because they were anti-dilutive. Assuming an average stock price of
$38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options
for the years ended December 31, 2009 and 2008 would have increased by 3.4 million and 0.3 million
shares, respectively.
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries.
At December 31, 2009, consolidated retained earnings included $5.6 billion of undistributed
retained earnings of the subsidiaries. Southern Powers credit facility contains potential
limitations on the payment of common stock dividends; as of December 31, 2009, Southern Power was
in compliance with all such requirements.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements
of indemnity with the NRC that, together with private insurance, cover third-party liability
arising from any nuclear incident occurring at the companies nuclear power plants. The Act
provides funds up to $12.6 billion for public liability claims that could arise from a single
nuclear incident. Each nuclear plant is insured against this liability to a maximum of
$375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a
mandatory program of deferred premiums that could be assessed, after a nuclear incident, against
all owners of commercial nuclear reactors. A company could be assessed up to $117.5 million per
incident for each licensed reactor it operates but not more than an aggregate of $17.5 million per
incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any
applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and
buyback interests, is $235 million and $237 million, respectively, per incident, but not more than
an aggregate of $35 million per company to be paid for each incident in any one year. Both the
maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at
least every five years. The next scheduled adjustment is due no later than October 29, 2013.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual
insurer established to provide property damage insurance in an amount up to $500 million for
members nuclear generating facilities.
Additionally, both companies have policies that currently provide decontamination, excess property
insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the
$500 million primary coverage. This excess insurance is also provided by NEIL. In the event of a
loss, the amount of insurance available may not be adequate to cover property damage and other
incurred expenses.
C-77
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
NEIL also covers the additional costs that would be incurred in obtaining replacement power during
a prolonged accidental outage at a 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 the maximum limit allowed by NEIL, subject to
ownership limitations. Each facility has elected a 12-week deductible waiting period.
Under each of the NEIL policies, members are subject to assessments if losses each year exceed the
accumulated funds available to the insurer under that policy. The current maximum annual
assessments for Alabama Power and Georgia Power under the NEIL policies would be $38 million and
$50 million, respectively.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to
normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from
terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover
through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC
requires that the proceeds of such policies shall be dedicated first for the sole purpose of
placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are
to be applied next toward the costs of decontamination and debris removal operations ordered by the
NRC, and any further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust indentures.
All retrospective assessments, whether generated for liability, property, or replacement power, may
be subject to applicable state premium taxes.
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a
market participant would use in pricing the asset or liability. The use of observable inputs is
maximized where available and the use of unobservable inputs is minimized for fair value
measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation
techniques used for fair value measurement.
|
|
Level 1 consists of observable market data in an active market for identical assets or
liabilities. |
|
|
|
Level 2 consists of observable market data, other than that included in Level 1, that is
either directly or indirectly observable. |
|
|
|
Level 3 consists of unobservable market data. The input may reflect the assumptions of
the Company of what a market participant would use in pricing an asset or liability. If
there is little available market data, then the 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.
C-78
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
As of December 31, 2009, assets and liabilities measured at fair value on a recurring basis
during the period, together with the level of the fair value hierarchy in which they fall, are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted Prices |
|
|
|
|
|
|
|
|
in Active |
|
Significant |
|
|
|
|
|
|
Markets for |
|
Other |
|
Significant |
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
|
|
Assets |
|
Inputs |
|
Inputs |
|
|
As of December 31, 2009: |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Total |
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives |
|
$ |
|
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
7 |
|
Interest rate derivatives |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Nuclear decommissioning trusts:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity |
|
|
724 |
|
|
|
50 |
|
|
|
|
|
|
|
774 |
|
U.S. Treasury and government agency
securities |
|
|
11 |
|
|
|
36 |
|
|
|
|
|
|
|
47 |
|
Municipal bonds |
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Corporate bonds |
|
|
|
|
|
|
137 |
|
|
|
|
|
|
|
137 |
|
Mortgage and asset backed securities |
|
|
|
|
|
|
65 |
|
|
|
|
|
|
|
65 |
|
Other |
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Cash equivalents and restricted cash |
|
|
623 |
|
|
|
|
|
|
|
|
|
|
|
623 |
|
Other |
|
|
3 |
|
|
|
48 |
|
|
|
35 |
|
|
|
86 |
|
|
Total |
|
$ |
1,361 |
|
|
$ |
391 |
|
|
$ |
35 |
|
|
$ |
1,787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives |
|
$ |
|
|
|
$ |
185 |
|
|
$ |
|
|
|
$ |
185 |
|
Interest rate derivatives |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
|
Total |
|
$ |
|
|
|
$ |
191 |
|
|
$ |
|
|
|
$ |
191 |
|
|
|
|
|
(a) |
|
Excludes receivables related to investment income, pending investment sales,
and payables related to pending investment purchases. |
Energy-related derivatives and interest rate derivatives primarily consist of
over-the-counter contracts. See Note 11 for additional information. The nuclear
decommissioning trust funds are invested in a diversified mix of equity and fixed income
securities. See Note 1 under Nuclear Decommissioning for additional information. The cash
equivalents and restricted cash consist of securities with original maturities of 90 days or
less. Other represents marketable securities and certain deferred compensation funds also
invested in various marketable securities. All of these financial instruments and investments
are valued primarily using the market approach.
As of December 31, 2009, the fair value measurements of investments calculated at net asset
value per share (or its equivalent), as well as the nature and risks of those investments, are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair |
|
Unfunded |
|
Redemption |
|
Redemption |
As of December 31, 2009: |
|
Value |
|
Commitments |
|
Frequency |
|
Notice Period |
|
|
(in millions) |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate bonds commingled funds |
|
$ |
14 |
|
|
None |
|
Daily |
|
|
1 to 3 days |
|
Other commingled funds |
|
|
13 |
|
|
None |
|
Daily |
|
Not applicable |
Trust owned life insurance |
|
|
78 |
|
|
None |
|
Daily |
|
15 days |
Cash equivalents and restricted cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market funds |
|
|
623 |
|
|
None |
|
Daily |
|
Not applicable |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred compensation money market
funds |
|
|
3 |
|
|
None |
|
Daily |
|
Not applicable |
C-79
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
The commingled funds in the nuclear decommissioning trusts invest primarily in a
diversified portfolio of investment high grade money market instruments, including, but not
limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness
with a maturity not exceeding 13 months from the date of purchase. The commingled funds will,
however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets
may be longer term investment grade fixed income obligations having a maximum five year final
maturity with put features or floating rates with a reset rate date of 13 months or less. The
primary objective for the commingled funds is a high level of current income consistent with
stability of principal and liquidity.
One of the nuclear decommissioning trusts includes investments in Trust-Owned Life Insurance
(TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the
impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds,
loans against the cash surrender value, and/or the cash surrender value, subject to legal
restrictions. The amounts reported in the tables above reflect the fair value of investments
the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does
not own the underlying investments, but the fair value of the investments approximates the cash
surrender value of the TOLI policies. The investments made by the insurer are in commingled
funds. The commingled funds primarily include investments in domestic and international equity
securities and predominantly high-quality fixed income securities. These fixed income
securities include U.S. Treasury and government agency fixed income securities, non-U.S.
government and agency fixed income securities, domestic and foreign corporate fixed income
securities, and, to some degree, mortgage and asset backed securities. The passively managed
funds seek to replicate the performance of a related index. The actively managed funds seek to
exceed the performance of a related index through security analysis and selection.
The money market funds are short-term investments of excess funds in various money market mutual
funds, which are portfolios of short-term debt securities. The money market funds are regulated
by the Securities and Exchange Commission and typically receive the highest rating from credit
rating agencies. Regulatory and rating agency requirements for money market funds include
minimum credit ratings and maximum maturities for individual securities and a maximum weighted
average portfolio maturity. Redemptions are available on a same day basis up to the full amount
of the Companys investment in the money market funds.
Changes in the fair value measurement of the Level 3 items using significant unobservable inputs
for Southern Company at December 31, 2009 and 2008 are as follows:
|
|
|
|
|
|
|
Level 3 |
|
|
Other |
|
|
(in millions) |
Beginning balance at December 31, 2008 |
|
$ |
35 |
|
Total gains (losses) realized/unrealized: |
|
|
|
|
Included in earnings |
|
|
(3 |
) |
Included in other comprehensive income |
|
|
3 |
|
|
Ending balance at December 31, 2009 |
|
$ |
35 |
|
|
Unrealized losses of $3 million were included in earnings during 2009 relating to assets still held
at December 31, 2009 and are recorded in depreciation and amortization.
As of December 31, 2009, other financial instruments for which the carrying amount did not equal
fair value were as follows:
|
|
|
|
|
|
|
|
|
|
|
Carrying Amount |
|
Fair Value |
|
|
(in millions) |
Long-term debt: |
|
|
|
|
|
|
|
|
2009 |
|
$ |
19,145 |
|
|
$ |
19,567 |
|
2008 |
|
$ |
17,327 |
|
|
$ |
17,114 |
|
The fair values were based on either closing market prices (Level 1) or closing prices of
comparable instruments (Level 2).
C-80
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
11. DERIVATIVES
Southern Company, the traditional operating companies, and Southern Power are exposed to market
risks, primarily commodity price risk and interest rate risk. To manage the volatility
attributable to these exposures, each company nets its exposures, where possible, to take advantage
of natural offsets and enters into various derivative transactions for the remaining exposures
pursuant to each 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.
Energy-Related Derivatives
The traditional operating companies and Southern Power enter into energy-related derivatives to
hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate
regulations, the traditional operating companies have limited exposure to market volatility in
commodity fuel prices and prices of electricity. Each of the traditional operating companies
manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs,
through the use of financial derivative contracts. Southern Power has limited exposure to market
volatility in commodity fuel prices and prices of electricity because its long-term sales contracts
shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has
been and may continue to be exposed to market volatility in energy-related commodity prices as a
result of sales of uncontracted generating capacity.
To mitigate residual risks relative to movements in electricity prices, the Company enters into
physical fixed-price or heat rate contracts for the purchase and sale of electricity through the
wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the
Company may enter into fixed-price contracts for natural gas purchases; however, a significant
portion of contracts are priced at market.
Energy-related derivative contracts are accounted for in one of three methods:
|
|
Regulatory Hedges Energy-related derivative contracts which are designated as regulatory
hedges relate primarily to the traditional operating companies fuel hedging programs, where
gains and losses are initially recorded as regulatory liabilities and assets, respectively,
and then are included in fuel expense as the underlying fuel is used in operations and
ultimately recovered through the respective fuel cost recovery clauses. |
|
|
|
Cash Flow Hedges Gains and losses on energy-related derivatives designated as cash flow
hedges are used to hedge anticipated purchases and sales and are initially deferred in other
comprehensive income (OCI) before being recognized in income in the same period as the hedged
transactions are reflected in earnings. |
|
|
|
Not Designated Gains and losses on energy-related derivative contracts that are not
designated or fail to qualify as hedges are recognized in the statements of income as
incurred. |
Some energy-related derivative contracts require physical delivery as opposed to financial
settlement, and this type of derivative is both common and prevalent within the electric industry.
When an energy-related derivative contract is settled physically, any cumulative unrealized gain or
loss is reversed and the contract price is recognized in the respective line item representing the
actual price of the underlying goods being delivered.
C-81
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
At December 31, 2009, the net volume of energy-related derivative contracts for power and natural
gas positions for Southern Company, together with the longest hedge date over which it is hedging
its exposure to the variability in future cash flows for forecasted transactions and the longest
date for derivatives not designated as hedges, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power |
|
|
Gas |
|
|
|
Longest |
|
|
Longest |
|
|
Net |
|
|
Longest |
|
|
Longest |
|
Net Sold |
|
Hedge |
|
|
Non-Hedge |
|
|
Purchased |
|
|
Hedge |
|
|
Non-Hedge |
|
Megawatt-hours |
|
Date |
|
|
Date |
|
|
mmBtu |
|
|
Date |
|
|
Date |
|
(in millions) |
|
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
2.6 |
|
|
2010 |
|
|
|
2010 |
|
|
|
154 |
* |
|
|
2014 |
|
|
|
2014 |
|
|
|
|
* |
|
Includes location basis of 2 million British thermal units (mmBtu). |
For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel
expense for the next 12-month period ending December 31, 2010 are immaterial.
Interest Rate Derivatives
Southern Company and certain subsidiaries also enter into interest rate derivatives, which include
forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives
related to existing variable rate securities or forecasted transactions are accounted for as cash
flow hedges. The derivatives employed as hedging instruments are structured to minimize
ineffectiveness.
For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into
earnings at the same time the hedged transactions affect earnings.
At December 31, 2009, Southern Company had a total of $976 million notional amount of interest rate
derivatives outstanding with net fair value losses of $3 million as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
Gain (Loss) |
|
|
|
Notional |
|
|
Variable Rate |
|
Fixed Rate |
|
Hedge Maturity |
|
December 31, |
|
|
|
Amount |
|
|
Received |
|
Paid |
|
Date |
|
2009 |
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
Cash flow hedges of existing debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
576 |
|
|
SIFMA* Index |
|
|
2.69 |
% |
|
February 2010 |
|
$ |
(4 |
) |
|
|
|
300 |
|
|
1-month LIBOR |
|
|
2.43 |
% |
|
April 2010 |
|
|
(2 |
) |
Cash flow hedges on forecasted debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100 |
|
|
3-month LIBOR |
|
|
3.79 |
% |
|
April 2020 |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA) |
For the year ended December 31, 2009, the Company had realized net losses of $19 million upon
termination of certain interest rate derivatives at the same time the related debt was issued. The
effective portion of these losses has been deferred in OCI and is being amortized to interest
expense over the life of the original interest rate derivative, reflecting the period in which the
forecasted hedged transaction affects earnings.
The estimated pre-tax losses that will be reclassified from OCI to interest expense for the next
12-month period ending December 31, 2010 is $25 million. The Company has deferred gains and losses
that are expected to be amortized into earnings through 2037.
C-82
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
Derivative Financial Statement Presentation and Amounts
At December 31, 2009 and 2008, the fair value of energy-related derivatives and interest rate
derivatives was reflected in the balance sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
Liability Derivatives |
|
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
Derivative Category |
|
Location |
|
2009 |
|
2008 |
|
Location |
|
2009 |
|
2008 |
|
|
|
|
(in millions) |
|
|
|
(in millions) |
Derivatives designated as hedging
instruments for regulatory purposes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives: |
|
Other
current
assets |
|
$ |
1 |
|
|
$ |
10 |
|
|
Liabilities
from risk
management activities |
|
$ |
111 |
|
|
$ |
215 |
|
|
|
Other
deferred charges
and assets |
|
|
1 |
|
|
|
|
|
|
Other
deferred credits
and liabilities |
|
|
66 |
|
|
|
83 |
|
|
Total derivatives designated as hedging instruments for regulatory purposes |
|
|
|
$ |
2 |
|
|
$ |
10 |
|
|
|
|
$ |
177 |
|
|
$ |
298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments in cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives: |
|
Other
current
assets |
|
$ |
3 |
|
|
$ |
|
|
|
Liabilities
from risk
management activities |
|
$ |
5 |
|
|
$ |
1 |
|
Interest rate derivatives: |
|
Other
current
assets |
|
|
3 |
|
|
|
|
|
|
Liabilities
from risk management activities |
|
|
6 |
|
|
|
37 |
|
|
|
Other
deferred charges
and assets |
|
|
|
|
|
|
|
|
|
Other
deferred credits
and liabilities |
|
|
|
|
|
|
3 |
|
|
Total derivatives designated as hedging instruments in cash flow hedges |
|
|
|
$ |
6 |
|
|
$ |
|
|
|
|
|
$ |
11 |
|
|
$ |
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-related derivatives: |
|
Other
current
assets |
|
$ |
2 |
|
|
$ |
12 |
|
|
Liabilities
from risk
management activities |
|
$ |
3 |
|
|
$ |
8 |
|
|
|
Total |
|
|
|
$ |
10 |
|
|
$ |
22 |
|
|
|
|
$ |
191 |
|
|
$ |
347 |
|
|
|
All derivative instruments are measured at fair value. See Note 10 for additional
information.
At December 31, 2009 and 2008, the pre-tax effect of unrealized derivative gains (losses) arising
from energy-related derivative instruments designated as regulatory hedging instruments and
deferred on the balance sheets were as follows:
|
|
|
|
Unrealized Losses |
|
Unrealized Gains |
|
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
Derivative Category |
|
Location |
|
2009 |
|
2008 |
|
Location |
|
2009 |
|
2008 |
|
|
|
|
(in millions) |
|
|
|
(in millions) |
Energy-related derivatives: |
|
Other
regulatory assets, current |
|
$ |
(111 |
) |
|
$ |
(215 |
) |
|
Other
regulatory liabilities, current |
|
$ |
1 |
|
|
$ |
10 |
|
|
|
Other
regulatory assets, deferred |
|
|
(66 |
) |
|
|
(83 |
) |
|
Other
regulatory liabilities, deferred |
|
|
1 |
|
|
|
|
|
|
Total energy-related derivative gains (losses) |
|
|
|
$ |
(177 |
) |
|
$ |
(298 |
) |
|
|
|
$ |
2 |
|
|
$ |
10 |
|
|
C-83
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related
derivatives and interest rate derivatives designated as cash flow hedging instruments on the
statements of income were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in |
|
Gain (Loss) Reclassified from Accumulated OCI into Income |
Derivatives
in Cash Flow |
|
OCI on Derivative |
|
(Effective Portion) |
Hedging Relationships |
|
(Effective Portion) |
|
|
|
|
Amount |
Derivative Category |
|
2009 |
|
2008 |
|
2007 |
|
Statements of Income Location |
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
|
|
|
|
(in millions) |
Energy-related derivatives |
|
$(2) |
|
$ |
(1 |
) |
|
$ |
(2 |
) |
|
Fuel |
|
$ |
|
$ |
|
|
|
$ |
|
|
Interest rate derivatives |
|
(5) |
|
|
(47 |
) |
|
|
(7 |
) |
|
Interest expense |
|
(46) |
|
|
(19 |
) |
|
|
(15 |
) |
|
Total |
|
$(7) |
|
$ |
(48 |
) |
|
$ |
(9 |
) |
|
|
|
|
|
$(46) |
|
$ |
(19 |
) |
|
$ |
(15 |
) |
|
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2009, 2008, and 2007, the pre-tax effect of energy-related
derivatives not designated as hedging instruments on the statements of income were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not Designated |
|
Unrealized Gain (Loss) Recognized in Income |
as Hedging Instruments |
|
|
|
Amount |
Derivative Category |
|
Statements of Income Location |
|
2009 |
|
2008 |
|
2007 |
|
|
|
|
(in millions) |
Energy-related derivatives: |
|
Wholesale revenues |
|
$ |
5 |
|
|
$ |
(2 |
) |
|
$ |
|
|
|
|
Fuel |
|
|
(6 |
) |
|
|
5 |
|
|
|
|
|
|
|
Purchased power |
|
|
(4 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
Other income (expense), net |
|
|
|
|
|
|
|
|
|
|
30 |
* |
|
Total |
|
|
|
$ |
(5 |
) |
|
$ |
1 |
|
|
$ |
30 |
|
|
|
|
|
* |
|
Includes a $27 million unrealized gain related to derivatives in place to reduce
exposure to a phase-out of certain
income tax credits related to synthetic fuel production in 2007. |
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment
schedules or terminations as a result of a credit rating downgrade. There are certain derivatives
that could require collateral, but not accelerated payment, in the event of various credit rating
changes of certain Southern Company subsidiaries. At December 31, 2009, the fair value of
derivative liabilities with contingent features was $33 million.
At December 31, 2009, the Company had no collateral posted with their derivative counterparties.
The maximum potential collateral requirement arising from the credit-risk-related contingent
features, at a rating below BBB- and/or Baa3, is $33 million. Generally, collateral may be
provided by a Southern Company guaranty, letter of credit, or cash. Included in these amounts are
certain agreements that could require collateral in the event that one or more Southern Company
system power pool participants has a credit rating change to below investment grade.
Currently, the Company has investment grade credit ratings from the major rating agencies with
respect to its debt.
C-84
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
12. SEGMENT AND RELATED INFORMATION
Southern Companys reportable business segments are the sale of electricity in the Southeast by the
four traditional operating companies and Southern Power. Southern Powers revenues from sales to
the traditional operating companies were $544 million, $638 million, and $547 million in 2009,
2008, and 2007, respectively. The All Other column includes parent Southern Company, which does
not allocate operating expenses to business segments. Also, this category includes segments below
the quantitative threshold for separate disclosure. These segments include investments in
telecommunications and leveraged lease projects. Also included are investments in synthetic fuels
for 2007. In addition, see Note 1 under Related Party Transactions for information regarding
revenues from services for synthetic fuel production that are included in the cost of fuel
purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material.
Financial data for business segments and products and services are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Utilities |
|
|
|
|
|
|
|
|
Traditional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
Southern |
|
|
|
|
|
|
|
|
|
All |
|
|
|
|
|
|
Companies |
|
Power |
|
Eliminations |
|
Total |
|
Other |
|
Eliminations |
|
Consolidated |
|
|
(in millions) |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
15,304 |
|
|
$ |
947 |
|
|
$ |
(609 |
) |
|
$ |
15,642 |
|
|
$ |
165 |
|
|
$ |
(64 |
) |
|
$ |
15,743 |
|
Depreciation and amortization |
|
|
1,378 |
|
|
|
98 |
|
|
|
|
|
|
|
1,476 |
|
|
|
27 |
|
|
|
|
|
|
|
1,503 |
|
Interest income |
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
|
|
3 |
|
|
|
(1 |
) |
|
|
23 |
|
Interest expense |
|
|
749 |
|
|
|
85 |
|
|
|
|
|
|
|
834 |
|
|
|
71 |
|
|
|
|
|
|
|
905 |
|
Income taxes |
|
|
902 |
|
|
|
86 |
|
|
|
|
|
|
|
988 |
|
|
|
(92 |
) |
|
|
|
|
|
|
896 |
|
Segment net income (loss)* |
|
|
1,679 |
|
|
|
156 |
|
|
|
|
|
|
|
1,835 |
|
|
|
(193 |
) |
|
|
1 |
|
|
|
1,643 |
|
Total assets |
|
|
48,403 |
|
|
|
3,043 |
|
|
|
(143 |
) |
|
|
51,303 |
|
|
|
1,223 |
|
|
|
(480 |
) |
|
|
52,046 |
|
Gross property additions |
|
|
4,568 |
|
|
|
331 |
|
|
|
|
|
|
|
4,899 |
|
|
|
14 |
|
|
|
|
|
|
|
4,913 |
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
16,521 |
|
|
$ |
1,314 |
|
|
$ |
(835 |
) |
|
$ |
17,000 |
|
|
$ |
182 |
|
|
$ |
(55 |
) |
|
$ |
17,127 |
|
Depreciation and amortization |
|
|
1,325 |
|
|
|
89 |
|
|
|
|
|
|
|
1,414 |
|
|
|
29 |
|
|
|
|
|
|
|
1,443 |
|
Interest income |
|
|
32 |
|
|
|
1 |
|
|
|
|
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
33 |
|
Interest expense |
|
|
689 |
|
|
|
83 |
|
|
|
|
|
|
|
772 |
|
|
|
94 |
|
|
|
|
|
|
|
866 |
|
Income taxes |
|
|
944 |
|
|
|
93 |
|
|
|
|
|
|
|
1,037 |
|
|
|
(122 |
) |
|
|
|
|
|
|
915 |
|
Segment net income (loss)* |
|
|
1,703 |
|
|
|
144 |
|
|
|
|
|
|
|
1,847 |
|
|
|
(104 |
) |
|
|
(1 |
) |
|
|
1,742 |
|
Total assets |
|
|
44,794 |
|
|
|
2,813 |
|
|
|
(139 |
) |
|
|
47,468 |
|
|
|
1,407 |
|
|
|
(528 |
) |
|
|
48,347 |
|
Gross property additions |
|
|
4,058 |
|
|
|
50 |
|
|
|
|
|
|
|
4,108 |
|
|
|
14 |
|
|
|
|
|
|
|
4,122 |
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
14,851 |
|
|
$ |
972 |
|
|
$ |
(683 |
) |
|
$ |
15,140 |
|
|
$ |
380 |
|
|
$ |
(167 |
) |
|
$ |
15,353 |
|
Depreciation and amortization |
|
|
1,141 |
|
|
|
74 |
|
|
|
|
|
|
|
1,215 |
|
|
|
30 |
|
|
|
|
|
|
|
1,245 |
|
Interest income |
|
|
31 |
|
|
|
1 |
|
|
|
|
|
|
|
32 |
|
|
|
14 |
|
|
|
(1 |
) |
|
|
45 |
|
Interest expense |
|
|
685 |
|
|
|
79 |
|
|
|
|
|
|
|
764 |
|
|
|
122 |
|
|
|
|
|
|
|
886 |
|
Income taxes |
|
|
866 |
|
|
|
84 |
|
|
|
|
|
|
|
950 |
|
|
|
(115 |
) |
|
|
|
|
|
|
835 |
|
Segment net income (loss)* |
|
|
1,582 |
|
|
|
132 |
|
|
|
|
|
|
|
1,714 |
|
|
|
22 |
|
|
|
(2 |
) |
|
|
1,734 |
|
Total assets |
|
|
41,812 |
|
|
|
2,769 |
|
|
|
(122 |
) |
|
|
44,459 |
|
|
|
1,767 |
|
|
|
(437 |
) |
|
|
45,789 |
|
Gross property additions |
|
|
3,465 |
|
|
|
184 |
|
|
|
(4 |
) |
|
|
3,645 |
|
|
|
13 |
|
|
|
|
|
|
|
3,658 |
|
|
|
|
|
* |
|
After dividends on preferred and preference stock of subsidiaries |
Products and Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Utilities Revenues |
Year |
|
Retail |
|
Wholesale |
|
Other |
|
Total |
|
|
(in millions) |
2009 |
|
$ |
13,307 |
|
|
$ |
1,802 |
|
|
$ |
533 |
|
|
$ |
15,642 |
|
2008 |
|
|
14,055 |
|
|
|
2,400 |
|
|
|
545 |
|
|
|
17,000 |
|
2007 |
|
|
12,639 |
|
|
|
1,988 |
|
|
|
513 |
|
|
|
15,140 |
|
|
C-85
NOTES (continued)
Southern Company and Subsidiary Companies 2009 Annual Report
13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2009 and 2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income After |
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on |
|
Per Common Share |
|
|
|
|
|
|
|
|
|
|
Preferred and |
|
|
|
|
|
|
|
|
|
Trading |
|
|
Operating |
|
Operating |
|
Preference Stock |
|
Basic |
|
|
|
|
|
Price Range |
Quarter Ended |
|
Revenues |
|
Income |
|
of Subsidiaries |
|
Earnings |
|
Dividends |
|
High |
|
Low |
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 2009 |
|
$ |
3,666 |
|
|
$ |
490 |
|
|
$ |
126 |
* |
|
$ |
0.16 |
* |
|
$ |
0.4200 |
|
|
$ |
37.62 |
|
|
$ |
26.48 |
|
June 2009 |
|
|
3,885 |
|
|
|
886 |
|
|
|
478 |
|
|
|
0.61 |
|
|
|
0.4375 |
|
|
|
32.05 |
|
|
|
27.19 |
|
September 2009 |
|
|
4,682 |
|
|
|
1,415 |
|
|
|
790 |
|
|
|
0.99 |
|
|
|
0.4375 |
|
|
|
32.67 |
|
|
|
30.27 |
|
December 2009 |
|
|
3,510 |
|
|
|
477 |
|
|
|
249 |
|
|
|
0.31 |
|
|
|
0.4375 |
|
|
|
34.47 |
|
|
|
30.89 |
|
|
March 2008 |
|
$ |
3,683 |
|
|
$ |
708 |
|
|
$ |
359 |
|
|
$ |
0.47 |
|
|
$ |
0.4025 |
|
|
$ |
40.60 |
|
|
$ |
33.71 |
|
June 2008 |
|
|
4,215 |
|
|
|
924 |
|
|
|
417 |
|
|
|
0.54 |
|
|
|
0.4200 |
|
|
|
37.81 |
|
|
|
34.28 |
|
September 2008 |
|
|
5,427 |
|
|
|
1,405 |
|
|
|
780 |
|
|
|
1.01 |
|
|
|
0.4200 |
|
|
|
40.00 |
|
|
|
34.46 |
|
December 2008 |
|
|
3,802 |
|
|
|
469 |
|
|
|
186 |
|
|
|
0.24 |
|
|
|
0.4200 |
|
|
|
38.18 |
|
|
|
29.82 |
|
|
Southern Companys business is influenced by seasonal weather conditions.
|
|
|
* |
|
Southern Companys MC Asset Recovery litigation settlement reduced earnings by $202
million, or 25 cents per share, during the first quarter of 2009. |
C-86
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2005 through 2009
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
Operating Revenues (in millions) |
|
$ |
15,743 |
|
|
$ |
17,127 |
|
|
$ |
15,353 |
|
|
$ |
14,356 |
|
|
$ |
13,554 |
|
Total Assets (in millions) |
|
$ |
52,046 |
|
|
$ |
48,347 |
|
|
$ |
45,789 |
|
|
$ |
42,858 |
|
|
$ |
39,877 |
|
Gross Property Additions (in millions) |
|
$ |
4,913 |
|
|
$ |
4,122 |
|
|
$ |
3,658 |
|
|
$ |
3,072 |
|
|
$ |
2,476 |
|
Return on Average Common Equity (percent) |
|
|
11.67 |
|
|
|
13.57 |
|
|
|
14.60 |
|
|
|
14.26 |
|
|
|
15.17 |
|
Cash Dividends Paid Per Share of Common Stock |
|
$ |
1.7325 |
|
|
$ |
1.6625 |
|
|
$ |
1.595 |
|
|
$ |
1.535 |
|
|
$ |
1.475 |
|
Consolidated Net Income After
Dividends on Preferred and Preference
Stock of Subsidiaries (in millions) |
|
$ |
1,643 |
|
|
$ |
1,742 |
|
|
$ |
1,734 |
|
|
$ |
1,573 |
|
|
$ |
1,591 |
|
Earnings Per Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.07 |
|
|
$ |
2.26 |
|
|
$ |
2.29 |
|
|
$ |
2.12 |
|
|
$ |
2.14 |
|
Diluted |
|
|
2.06 |
|
|
|
2.25 |
|
|
|
2.28 |
|
|
|
2.10 |
|
|
|
2.13 |
|
|
Capitalization (in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock equity |
|
$ |
14,878 |
|
|
$ |
13,276 |
|
|
$ |
12,385 |
|
|
$ |
11,371 |
|
|
$ |
10,689 |
|
Preferred and preference stock of subsidiaries |
|
|
707 |
|
|
|
707 |
|
|
|
707 |
|
|
|
246 |
|
|
|
98 |
|
Redeemable preferred stock of subsidiaries |
|
|
375 |
|
|
|
375 |
|
|
|
373 |
|
|
|
498 |
|
|
|
498 |
|
Long-term debt |
|
|
18,131 |
|
|
|
16,816 |
|
|
|
14,143 |
|
|
|
12,503 |
|
|
|
12,846 |
|
|
Total (excluding amounts due within one year) |
|
$ |
34,091 |
|
|
$ |
31,174 |
|
|
$ |
27,608 |
|
|
$ |
24,618 |
|
|
$ |
24,131 |
|
|
Capitalization Ratios (percent): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock equity |
|
|
43.6 |
|
|
|
42.6 |
|
|
|
44.9 |
|
|
|
46.2 |
|
|
|
44.3 |
|
Preferred and preference stock of subsidiaries |
|
|
2.1 |
|
|
|
2.3 |
|
|
|
2.6 |
|
|
|
1.0 |
|
|
|
0.4 |
|
Redeemable preferred stock of subsidiaries |
|
|
1.1 |
|
|
|
1.2 |
|
|
|
1.3 |
|
|
|
2.0 |
|
|
|
2.1 |
|
Long-term debt |
|
|
53.2 |
|
|
|
53.9 |
|
|
|
51.2 |
|
|
|
50.8 |
|
|
|
53.2 |
|
|
Total (excluding amounts due within one year) |
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
Other Common Stock Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Book value per share |
|
$ |
18.15 |
|
|
$ |
17.08 |
|
|
$ |
16.23 |
|
|
$ |
15.24 |
|
|
$ |
14.42 |
|
Market price per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
37.62 |
|
|
$ |
40.60 |
|
|
$ |
39.35 |
|
|
$ |
37.40 |
|
|
$ |
36.47 |
|
Low |
|
|
26.48 |
|
|
|
29.82 |
|
|
|
33.16 |
|
|
|
30.48 |
|
|
|
31.14 |
|
Close (year-end) |
|
|
33.32 |
|
|
|
37.00 |
|
|
|
38.75 |
|
|
|
36.86 |
|
|
|
34.53 |
|
Market-to-book ratio (year-end) (percent) |
|
|
183.6 |
|
|
|
216.6 |
|
|
|
238.8 |
|
|
|
241.9 |
|
|
|
239.5 |
|
Price-earnings ratio (year-end) (times) |
|
|
16.1 |
|
|
|
16.4 |
|
|
|
16.9 |
|
|
|
17.4 |
|
|
|
16.1 |
|
Dividends paid (in millions) |
|
$ |
1,369 |
|
|
$ |
1,279 |
|
|
$ |
1,204 |
|
|
$ |
1,140 |
|
|
$ |
1,098 |
|
Dividend yield (year-end) (percent) |
|
|
5.2 |
|
|
|
4.5 |
|
|
|
4.1 |
|
|
|
4.2 |
|
|
|
4.3 |
|
Dividend payout ratio (percent) |
|
|
83.3 |
|
|
|
73.5 |
|
|
|
69.5 |
|
|
|
72.4 |
|
|
|
69.0 |
|
Shares outstanding (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
794,795 |
|
|
|
771,039 |
|
|
|
756,350 |
|
|
|
743,146 |
|
|
|
743,927 |
|
Year-end |
|
|
819,647 |
|
|
|
777,192 |
|
|
|
763,104 |
|
|
|
746,270 |
|
|
|
741,448 |
|
Stockholders of record (year-end) |
|
|
92,799 |
|
|
|
97,324 |
|
|
|
102,903 |
|
|
|
110,259 |
|
|
|
118,285 |
|
|
Traditional Operating Company Customers
(year-end) (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
3,798 |
|
|
|
3,785 |
|
|
|
3,756 |
|
|
|
3,706 |
|
|
|
3,642 |
|
Commercial |
|
|
580 |
|
|
|
594 |
|
|
|
600 |
|
|
|
596 |
|
|
|
586 |
|
Industrial |
|
|
15 |
|
|
|
15 |
|
|
|
15 |
|
|
|
15 |
|
|
|
15 |
|
Other |
|
|
9 |
|
|
|
8 |
|
|
|
6 |
|
|
|
5 |
|
|
|
5 |
|
|
Total |
|
|
4,402 |
|
|
|
4,402 |
|
|
|
4,377 |
|
|
|
4,322 |
|
|
|
4,248 |
|
|
Employees (year-end) |
|
|
26,112 |
|
|
|
27,276 |
|
|
|
26,472 |
|
|
|
26,091 |
|
|
|
25,554 |
|
|
C-87
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2005 through 2009
Southern Company and Subsidiary Companies 2009 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
Operating Revenues (in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
5,481 |
|
|
$ |
5,476 |
|
|
$ |
5,045 |
|
|
$ |
4,716 |
|
|
$ |
4,376 |
|
Commercial |
|
|
4,901 |
|
|
|
5,018 |
|
|
|
4,467 |
|
|
|
4,117 |
|
|
|
3,904 |
|
Industrial |
|
|
2,806 |
|
|
|
3,445 |
|
|
|
3,020 |
|
|
|
2,866 |
|
|
|
2,785 |
|
Other |
|
|
119 |
|
|
|
116 |
|
|
|
107 |
|
|
|
102 |
|
|
|
100 |
|
|
Total retail |
|
|
13,307 |
|
|
|
14,055 |
|
|
|
12,639 |
|
|
|
11,801 |
|
|
|
11,165 |
|
Wholesale |
|
|
1,802 |
|
|
|
2,400 |
|
|
|
1,988 |
|
|
|
1,822 |
|
|
|
1,667 |
|
|
Total revenues from sales of electricity |
|
|
15,109 |
|
|
|
16,455 |
|
|
|
14,627 |
|
|
|
13,623 |
|
|
|
12,832 |
|
Other revenues |
|
|
634 |
|
|
|
672 |
|
|
|
726 |
|
|
|
733 |
|
|
|
722 |
|
|
Total |
|
$ |
15,743 |
|
|
$ |
17,127 |
|
|
$ |
15,353 |
|
|
$ |
14,356 |
|
|
$ |
13,554 |
|
|
Kilowatt-Hour Sales (in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
51,690 |
|
|
|
52,262 |
|
|
|
53,326 |
|
|
|
52,383 |
|
|
|
51,082 |
|
Commercial |
|
|
53,526 |
|
|
|
54,427 |
|
|
|
54,665 |
|
|
|
52,987 |
|
|
|
51,857 |
|
Industrial |
|
|
46,422 |
|
|
|
52,636 |
|
|
|
54,662 |
|
|
|
55,044 |
|
|
|
55,141 |
|
Other |
|
|
953 |
|
|
|
934 |
|
|
|
962 |
|
|
|
920 |
|
|
|
996 |
|
|
Total retail |
|
|
152,591 |
|
|
|
160,259 |
|
|
|
163,615 |
|
|
|
161,334 |
|
|
|
159,076 |
|
Wholesale sales |
|
|
33,503 |
|
|
|
39,368 |
|
|
|
40,745 |
|
|
|
38,460 |
|
|
|
37,072 |
|
|
Total |
|
|
186,094 |
|
|
|
199,627 |
|
|
|
204,360 |
|
|
|
199,794 |
|
|
|
196,148 |
|
|
Average Revenue Per Kilowatt-Hour (cents): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
10.60 |
|
|
|
10.48 |
|
|
|
9.46 |
|
|
|
9.00 |
|
|
|
8.57 |
|
Commercial |
|
|
9.16 |
|
|
|
9.22 |
|
|
|
8.17 |
|
|
|
7.77 |
|
|
|
7.53 |
|
Industrial |
|
|
6.04 |
|
|
|
6.54 |
|
|
|
5.52 |
|
|
|
5.21 |
|
|
|
5.05 |
|
Total retail |
|
|
8.72 |
|
|
|
8.77 |
|
|
|
7.72 |
|
|
|
7.31 |
|
|
|
7.02 |
|
Wholesale |
|
|
5.38 |
|
|
|
6.10 |
|
|
|
4.88 |
|
|
|
4.74 |
|
|
|
4.50 |
|
Total sales |
|
|
8.12 |
|
|
|
8.24 |
|
|
|
7.16 |
|
|
|
6.82 |
|
|
|
6.54 |
|
Average Annual Kilowatt-Hour |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Use Per Residential Customer |
|
|
13,607 |
|
|
|
13,844 |
|
|
|
14,263 |
|
|
|
14,235 |
|
|
|
14,084 |
|
Average Annual Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Residential Customer |
|
$ |
1,443 |
|
|
$ |
1,451 |
|
|
$ |
1,349 |
|
|
$ |
1,282 |
|
|
$ |
1,207 |
|
Plant Nameplate Capacity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratings (year-end) (megawatts) |
|
|
42,932 |
|
|
|
42,607 |
|
|
|
41,948 |
|
|
|
41,785 |
|
|
|
40,509 |
|
Maximum Peak-Hour Demand (megawatts): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Winter |
|
|
33,519 |
|
|
|
32,604 |
|
|
|
31,189 |
|
|
|
30,958 |
|
|
|
30,384 |
|
Summer |
|
|
34,471 |
|
|
|
37,166 |
|
|
|
38,777 |
|
|
|
35,890 |
|
|
|
35,050 |
|
System Reserve Margin (at peak) (percent) |
|
|
26.4 |
|
|
|
15.3 |
|
|
|
11.2 |
|
|
|
17.1 |
|
|
|
14.4 |
|
Annual Load Factor (percent) |
|
|
60.6 |
|
|
|
58.7 |
|
|
|
57.6 |
|
|
|
60.8 |
|
|
|
60.2 |
|
Plant Availability (percent): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fossil-steam |
|
|
91.3 |
|
|
|
90.5 |
|
|
|
90.5 |
|
|
|
89.3 |
|
|
|
89.0 |
|
Nuclear |
|
|
90.1 |
|
|
|
91.3 |
|
|
|
90.8 |
|
|
|
91.5 |
|
|
|
90.5 |
|
|
Source of Energy Supply (percent): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal |
|
|
54.7 |
|
|
|
64.0 |
|
|
|
67.1 |
|
|
|
67.2 |
|
|
|
67.4 |
|
Nuclear |
|
|
14.9 |
|
|
|
14.0 |
|
|
|
13.4 |
|
|
|
14.0 |
|
|
|
14.0 |
|
Hydro |
|
|
3.9 |
|
|
|
1.4 |
|
|
|
0.9 |
|
|
|
1.9 |
|
|
|
3.1 |
|
Oil and gas |
|
|
22.5 |
|
|
|
15.4 |
|
|
|
15.0 |
|
|
|
12.9 |
|
|
|
10.9 |
|
Purchased power |
|
|
4.0 |
|
|
|
5.2 |
|
|
|
3.6 |
|
|
|
4.0 |
|
|
|
4.6 |
|
|
Total |
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
|
100.0 |
|
|
C-88
MANAGEMENT
COUNCIL
1. David
M. Ratcliffe
Chairman,
President, and CEO
Ratcliffe, 61, joined the Company as a biologist with Georgia
Power in 1971 and has been in his current position since 2004.
From 1999 to 2004, he was president and CEO of Georgia Power,
Southern Companys largest subsidiary, and from 1991 to
1995 he served as president and CEO of Mississippi Power.
Ratcliffe has held executive and management positions in the
areas of finance, external affairs, fuel services, operations
and planning, and research and environmental affairs.
2. W.
Paul Bowers
Executive Vice President and
Chief Financial Officer
Bowers, 53, joined the Company as a residential sales
representative with Gulf Power in 1979. He has held his current
position since 2008. Previously, he served as president of
Southern Company Generation. He also served as president and CEO
of Southern Power, president and CEO of Southern Companys
former United Kingdom subsidiary, and senior vice president and
chief marketing officer for Southern Company and held executive
positions at Georgia Power.
3. Thomas
A. Fanning
Executive Vice President and
Chief Operating Officer
Fanning, 53, joined the Company as a financial analyst in 1980.
In his current position since 2008, Fanning is responsible for
Southern Company Generation, Southern Power, and Southern
Company Transmission, as well as leading Southern Companys
efforts on business strategy and associated planning issues. He
has served as president and CEO of Gulf Power and chief
financial officer for both Southern Company, Georgia Power, and
Mississippi Power.
4. Michael
D. Garrett
Executive Vice President
President and CEO, Georgia Power
Garrett, 60, joined the Company as a cooperative-education
student with Georgia Power in 1968. He assumed his current
position in 2004. Previously, Garrett was president and CEO of
Mississippi Power. He has held executive positions at Alabama
Power in customer operations, regulatory affairs, finance, and
external affairs and also served as Birmingham Division vice
president.
5. G.
Edison Holland, Jr.
Executive Vice President, General Counsel,
and Corporate Secretary
Holland, 57, joined the Company as vice president and corporate
counsel for Gulf Power in 1992. He was named to his current
position, which includes serving as the chief compliance
officer, in 2001. Previously, he was president and CEO of
Savannah Electric and vice president of power generation and
transmission at Gulf Power.
6. C.
Alan Martin
Executive Vice President
President and CEO, Southern Company Services
Martin, 61, joined the Company as a
right-of-way
agent at Alabama Power in 1972. He has held his current position
since 2008. Martin previously served as executive vice president
and chief marketing officer for Southern Company, as well as
vice president of human resources. Most recently, he was
executive vice president of Alabama Power, with responsibility
for the customer service organization. Martin has also served as
executive vice president of external affairs at Alabama Power
and has held a number of other executive and management
positions at that company.
7. Charles
D. McCrary
Executive Vice President
President and CEO, Alabama Power
McCrary, 58, joined the Company as an assistant project planning
engineer with Alabama Power in 1973. He assumed his current
position in 2001. Previously, McCrary was chief production
officer for Southern Company and president and CEO of Southern
Power. He has held executive positions at Alabama Power and
Southern Nuclear as well as various jobs in engineering, system
planning, fuels, and environmental affairs.
8. James
H. Miller III
President and CEO, Southern Nuclear
Miller, 60, joined the Company as general counsel for Southern
Nuclear in 1994. He assumed his current position in 2008.
Previously, Miller served as senior vice president, compliance
officer, and general counsel for Georgia Power. He also has held
the positions of senior vice president of external affairs and
senior vice president of the Birmingham Division at Alabama
Power.
C-89
9. Susan
N. Story
President and CEO, Gulf Power
Story, 50, joined the Company as a nuclear power plant engineer
in 1982. She has held her current position since 2003.
Previously, Story was executive vice president of engineering
and construction services for Southern Company Generation and
Energy Marketing. She has held executive and management
positions in the areas of supply chain management, real estate,
corporate services, and human resources.
10. Anthony
J. Topazi
President and CEO, Mississippi Power
Topazi, 59, joined the Company as a cooperative-education
student with Alabama Power in 1969. He began his current
position in 2004. Topazi previously was executive vice president
for Southern Company Generation and Energy Marketing and also
served as senior vice president of Southern Power. He has held
various positions at Alabama Power, including Western Division
vice president and Birmingham Division vice president.
11. Christopher
C. Womack
Executive Vice President and
President, External Affairs
Womack, 52, 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
held numerous executive and management positions including the
Companys senior vice president of human resources and
chief people officer, 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 13 through 22 of the attached Proxy Statement.
C-90
STOCKHOLDER
INFORMATION
Transfer
Agent
SCS Stockholder Services is Southern Companys transfer
agent, dividend-paying agent, investment plan administrator, and
registrar.
If you have questions concerning your Southern Company
stockholder account, please contact:
By mail
SCS Stockholder Services
P.O. Box 54250
Atlanta, GA
30308-0250
By phone
9 to 5 ET
Monday through Friday
800-554-7626
By courier
SCS Stockholder Services
30 Ivan Allen Jr. Blvd. NW
11th Floor-Bin SC1100
Atlanta, GA 30308
By
e-mail
stockholders@southerncompany.com
Stockholder
Services Internet Site
Located within Southern Companys Investor Relations
website at
http://investor.southerncompany.com,
the Stockholder Services site provides transfer instructions,
service request forms, and answers to frequently asked
questions. Through this site, registered stockholders may also
securely access their account information, including share
balance, market value, and dividend payment details, as well as
change their account mailing addresses.
Southern
Investment Plan
The Southern Investment Plan provides a convenient way to
purchase common stock and reinvest dividends. You can access the
Stockholder Services Internet site to review the Prospectus and
download an enrollment form.
Direct
Registration
Southern Company common stock can be issued in direct
registration (uncertificated) form. The stock is Direct
Registration System eligible.
Dividend
Payments
The entire amount of dividends paid in 2009 is taxable. The
board of directors sets the record and payment dates for
quarterly dividends. A dividend of 43.75 cents per share was
paid in March 2010. For the remainder of 2010, projected record
dates are May 3, August 2, and November 1.
Projected payment dates for dividends declared during the
remainder of 2010 are June 5, September 4, and
December 6.
Auditors
Deloitte & Touche LLP
191 Peachtree St. NE
Suite 1500
Atlanta, GA 30303
During 2009, there were no changes in or disagreements with the
auditors on accounting and financial disclosure.
C-91
Investor
Information Line
For recorded information about earnings and dividends, stock
quotes, and current news releases, call toll-free
866-762-6411.
Institutional
Investor Inquiries
Southern Company maintains an investor relations office in
Atlanta,
404-506-5195
to meet the information needs of institutional investors and
securities analysts.
Electronic
Delivery Of Proxy Materials
Any stockholder may enroll for electronic delivery of proxy
materials at www.icsdelivery.com/so.
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/and in print. To request
printed materials, write to:
Chris Hobson
Senior Vice President, Research and Environmental Affairs
600 North 18th St.
Bin 14N-8195
Birmingham, AL
35203-2206
Common
Stock
Southern Company common stock is listed on the NYSE under the
ticker symbol SO. On December 31, 2009, Southern Company
had 92,799 stockholders of record.
C-92
C/O
PROXY SERVICES
P.
O. BOX 9112
FARMINGDALE,
NY 11735
|
If
you vote by Internet or Phone, please do not mail this
form.
VOTE BY
INTERNET - www.proxyvote.com
Use
the Internet to transmit your voting instructions and for electronic
delivery of information up until 11:59 P.M. Eastern Time the day before
the cut-off date or meeting date. Have your proxy card in hand when you
access the website and follow the instructions to obtain your records and
to create an electronic voting instruction form.
VOTE BY
PHONE - 1-800-690-6903
Use
any touch-tone telephone to
transmit your voting instructions up
until 11:59 P.M. Eastern Time the day before the cut-off date or meeting
date. Have your proxy card in hand when you call and then follow the
instructions.
VOTE
BY MAIL
Mark,
sign and date this form and return it in the postage-paid envelope we have
provided or return it to The Southern Company, c/o Broadridge, 51 Mercedes
Way, Edgewood, NY 11717.
ELECTRONIC DELIVERY OF
FUTURE PROXY MATERIALS
If
you would like to reduce the costs incurred by The Southern Company in
mailing proxy materials, you can consent to receiving all future proxy
statements with annual reports and proxy cards electronically via the
Internet. To sign up for electronic delivery, please follow the
instructions above to vote using the Internet and, when prompted, indicate
that you agree to receive materials electronically in future
years.
THANK
YOU
VIEW
THE PROXY STATEMENT ON THE INTERNET
www.southerncompany.com
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TO
VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
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M23189-P93798
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KEEP THIS PORTION FOR YOUR RECORDS
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THIS
FORM OF
PROXY OR TRUSTE
E VOTING INSTRUCTION FORM IS VALID
ONLY WHEN SIGNED AND
DATED. DETACH AND RETURN THIS PORTION ONLY
THE
SOUTHERN COMPANY
The Board of Directors recommends a vote
FOR Items 1, 2, 3, 4, and 5.
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For
All
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Withhold
All
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For
All
Except
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To
withhold authority to vote for any individual nominee(s), mark “For All
Except” and write the number(s) of the nominee(s) on the line
below
|
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0
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0
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0
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______________________________________
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1. ELECTION
OF DIRECTORS
Nominees:
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01)
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J.
P. Baranco
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07)
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D.
M. James
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02)
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J.
A. Boscia
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08)
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J.
N. Purcell
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03)
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H.
A. Clark III
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09)
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D.
M. Ratcliffe
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04)
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H.
W. Habermeyer, Jr.
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10)
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W.
G. Smith, Jr.
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05)
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V.
M. Hagen
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11)
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L.
D. Thompson
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06)
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W.
A. Hood, Jr.
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|
|
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|
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For
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Against
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Abstain
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2.
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RATIFICATION
OF THE APPOINTMENT OF DELOITTE & TOUCHE LLP AS THE
COMPANY’S INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR
2010
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0
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0
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0
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3.
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AMENDMENT
OF COMPANY’S BY-LAWS REGARDING MAJORITY VOTING AND CUMULATIVE
VOTING
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0
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0
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0
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4.
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AMENDMENT
OF COMPANY’S CERTIFICATE OF INCORPORATION REGARDING CUMULATIVE
VOTING
|
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0
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0
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0
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5.
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AMENDMENT
OF COMPANY’S CERTIFICATE OF INCORPORATION TO INCREASE NUMBER OF AUTHORIZED
SHARES OF COMMON STOCK
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|
0
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0
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0
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The
Board of Directors recommends a vote AGAINST Items 6 and 7.
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|
|
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6.
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STOCKHOLDER
PROPOSAL ON CLIMATE CHANGE ENVIRONMENTAL REPORT
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0 |
0
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0
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7.
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STOCKHOLDER
PROPOSAL ON COAL COMBUSTION BYPRODUCTS ENVIRONMENTAL
REPORT
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0
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0
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0
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|
|
|
|
|
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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 either paper or electronic prior to the deadline will be the instruction included in the
final tabulation.
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|
|
|
|
|
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Signature
[PLEASE SIGN WITHIN BOX]
|
Date
|
|
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Signature
(Joint Owners)
|
Date
|
Admission
Ticket
(Not
Transferable)
2010
Annual Meeting of Stockholders
10
A.M. ET, May 26, 2010
|
![](socoproxybandw.gif) |
The
Lodge Conference Center at Callaway Gardens
Highway
18
Pine Mountain, GA 31822
|
|
Please
present this Admission Ticket in order to gain
admittance
to the meeting.
|
Ticket
admits only the stockholder(s) listed on reverse
side
and is not transferable.
|
Directions to Meeting Site:
From Atlanta, GA - Take I-85 south to
I-185 (Exit 21), then Exit 34, Georgia Highway 18. Take Georgia Highway 18
east
to
Callaway.
From Birmingham, AL - Take U.S. Highway 280
east to Opelika, AL, then I-85 north to Georgia Highway 18 (Exit 2). Take
Georgia Highway 18 east to Callaway.
Important
Notice Regarding Internet Availability of Proxy Materials for the Annual
Meeting:
The Notice and Proxy Statement with Annual
Report are available at www.proxyvote.com.
|
|
M23190-P93798
|
FORM
OF PROXY AND
TRUSTEE
VOTING INSTRUCTION FORM
|
![](socoproxybandw.gif) |
FORM
OF PROXY AND
TRUSTEE
VOTING INSTRUCTION FORM
|
PROXY
SOLICITED ON BEHALF OF BOARD OF DIRECTORS AND ESP TRUSTEE
If a
stockholder of record, the undersigned hereby appoints D. M. Ratcliffe, W. P.
Bowers and G. E. Holland, Jr., or any of them, Proxies, with full power of
substitution in each, to vote all shares the undersigned is entitled to vote at
the Annual Meeting of Stockholders of The Southern Company, to be held at The
Lodge Conference Center at Callaway Gardens in Pine Mountain, Georgia, on May
26, 2010, at 10:00 a.m., ET, and any adjournments thereof, on all matters
properly coming before the meeting, including, without limitation, the items
listed on the reverse side of this form.
If a
beneficial owner holding shares through the Employee Savings Plan (ESP), the
undersigned directs the Trustee of the Plan to vote all shares the undersigned
is entitled to vote at the Annual Meeting of Stockholders, and any adjournments
thereof, on all matters properly coming before the meeting, including, without
limitation, the items listed on the reverse side of this form.
This Form
of Proxy/Trustee Voting Instruction Form is solicited jointly by the Board of
Directors of The Southern Company and the Trustee of the ESP pursuant to a
separate Notice of Annual Meeting and Proxy Statement. If not voted
electronically, this form should be mailed in the enclosed envelope to the
Company's proxy tabulator at 51 Mercedes Way, Edgewood, NY 11717. The deadline
for receipt of Trustee Voting Instruction Forms for the ESP is 5:00 p.m. on
Monday, May 24, 2010. The deadline for receipt of shares of record voted through
the Form of Proxy is 9:00 a.m. on Wednesday, May 26, 2010. The deadline for
receipt of instructions provided electronically is 11:59 p.m. on Tuesday, May
25, 2010.
The proxy
tabulator will report separately to the Proxies named above and to the Trustee
as to proxies received and voting instructions provided,
respectively.
THIS
FORM OF PROXY/TRUSTEE VOTING INSTRUCTION FORM WILL BE VOTED AS
SPECIFIED
|
BY
THE UNDERSIGNED. IF NO CHOICE IS INDICATED, THE SHARES WILL BE
VOTED AS THE
|
BOARD
OF DIRECTORS RECOMMENDS.
|
Continued
and to be voted and signed on reverse side.
*** IMPORTANT MESSAGE ABOUT VOTING YOUR SHARES ***
Recently,
NYSE and SEC rule changes were enacted changing how shares held in brokerage
accounts are voted in director elections. If YOU do not vote your
shares on proposal one (Election of Directors), your brokerage firm can no
longer vote them for you; your shares will remain
unvoted. Previously, if your broker did not receive instructions from
you, they were permitted to vote your shares for you in director
elections. However, starting January 1, 2010, under changes to NYSE
Rule 452, brokers will no longer be allowed to vote uninstructed
shares.
Therefore,
it is very important that you vote your shares for all proposals including the
election of directors.
In
addition to checking the appropriate boxes on the enclosed vote instruction
form, signing and returning it in the enclosed postage paid envelope,
there are two additional convenient ways to vote that are available
24 hours a day:
Vote by Internet
|
Vote by Telephone
|
Go to website: www.proxyvote.com |
Call
toll-free on a touch-tone phone in the U.S. or Canada |
Follow
these four easy steps:
|
Follow
these four easy steps:
|
Read the accompanying
Proxy materials.
|
Read the accompanying
Proxy materials.
|
Go to website www.proxyvote.com.
|
Call
the toll-free phone number printed on the enclosed vote
instruction form.
|
Have your vote instruction form in hand when you
access the website.
|
Have your vote instruction form in hand when you call the
toll-free number.
|
Follow the simple instructions.
|
Follow the recorded instructions:
* Press
1 to vote as the Board recommends
* Press 2 to vote each proposal individually
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********* Note **********
|
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When
voting online, you may also elect to give your consent to have all future
proxy materials delivered to you electronically.
|
|
Do
not return your vote instruction form if you are voting by Internet or
Telephone
|
|