e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2010
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
EXCHANGE ACT OF 1934 |
For the Transition Period from to
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Commission |
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Registrant, State of Incorporation, |
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I.R.S. Employer |
File Number |
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Address and Telephone Number |
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Identification No. |
1-3526
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The Southern Company
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58-0690070 |
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(A Delaware Corporation) |
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30 Ivan Allen Jr. Boulevard, N.W. |
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Atlanta, Georgia 30308 |
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(404) 506-5000 |
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1-3164
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Alabama Power Company
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63-0004250 |
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(An Alabama Corporation) |
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600 North 18th Street |
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Birmingham, Alabama 35291 |
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(205) 257-1000 |
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1-6468
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Georgia Power Company
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58-0257110 |
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(A Georgia Corporation) |
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241 Ralph McGill Boulevard, N.E. |
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Atlanta, Georgia 30308 |
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(404) 506-6526 |
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001-31737
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Gulf Power Company
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59-0276810 |
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(A Florida Corporation) |
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One Energy Place |
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Pensacola, Florida 32520 |
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(850) 444-6111 |
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001-11229
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Mississippi Power Company
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64-0205820 |
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(A Mississippi Corporation) |
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2992 West Beach |
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Gulfport, Mississippi 39501 |
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(228) 864-1211 |
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333-98553
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Southern Power Company
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58-2598670 |
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(A Delaware Corporation) |
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30 Ivan Allen Jr. Boulevard, N.W. |
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Atlanta, Georgia 30308 |
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(404) 506-5000 |
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Securities registered pursuant to Section 12(b) of the Act:1
Each of the following classes or series of securities registered pursuant to Section 12(b) of the
Act is listed on the New York Stock Exchange.
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Title of each class |
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Registrant |
Common Stock, $5 par value
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The Southern Company |
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Class A preferred, cumulative, $25 stated capital |
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Alabama Power Company |
5.20% Series
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5.83% Series |
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5.30% Series |
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Senior Notes |
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5 7/8% Series GG
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5.875% Series II |
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5.875% Series 2007B
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6.375% Series JJ |
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Class A Preferred Stock, non-cumulative,
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Georgia Power Company |
Par value $25 per share |
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6 1/8% Series |
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Senior Notes |
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6.375% Series 2007D |
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8.20% Series 2008C |
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Long-term debt payable to affiliated trusts, |
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$25 liquidation amount |
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5 7/8% Trust Preferred Securities2 |
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Senior Notes
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Gulf Power Company |
5.25% Series H |
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Senior Notes
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Mississippi Power Company |
5 5/8% Series E |
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Depositary preferred shares, each representing
one-fourth
of a share of preferred stock,
cumulative, $100 par value |
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5.25% Series |
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As of December 31, 2010. |
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2 |
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Issued by Georgia Power Capital Trust VII and guaranteed by Georgia Power Company. |
Securities registered pursuant to Section 12(g) of the Act:3
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Title of each class |
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Registrant |
Preferred stock, cumulative, $100 par value |
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Alabama Power Company |
4.20% Series
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4.60% Series
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4.72% Series |
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4.52% Series
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4.64% Series
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4.92% Series |
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Preferred stock, cumulative, $100 par value |
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Mississippi Power Company |
4.40% Series
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4.60% Series
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4.72% Series |
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3 |
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As of December 31, 2010. |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
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Registrant |
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Yes |
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No |
The Southern Company |
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ü |
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Alabama Power Company |
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Georgia Power Company |
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Gulf Power Company |
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ü |
Mississippi Power Company |
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ü |
Southern Power Company |
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ü |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o No þ (Response applicable to all registrants.)
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrants were required to file such reports), and (2) have been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrants have submitted electronically and posted on their
corporate web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrants were required to submit and post such files). Yes þ No o (Response
applicable only to The Southern Company at this time.)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
(Check one):
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Large |
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Smaller |
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Accelerated |
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Accelerated |
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Non-accelerated |
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Reporting |
Registrant |
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Filer |
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Filer |
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Filer |
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Company |
The Southern Company
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Alabama Power Company
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Georgia Power Company
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ü |
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Gulf Power Company
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ü |
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Mississippi Power Company
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ü |
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Southern Power Company
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ü |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ (Response applicable to all registrants.)
Aggregate market value of The Southern Companys common stock held by non-affiliates of The
Southern Company at June 30, 2010: $27.6 billion. All of the common stock of the other registrants
is held by The Southern Company. A description of each registrants common stock follows:
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Description of |
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Shares Outstanding |
Registrant |
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Common Stock |
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at January 31, 2011 |
The Southern Company |
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Par Value $5 Per Share |
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845,614,704 |
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Alabama Power Company |
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Par Value $40 Per Share |
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30,537,500 |
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Georgia Power Company |
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Without Par Value |
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9,261,500 |
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Gulf Power Company |
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Without Par Value |
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4,142,717 |
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Mississippi Power Company |
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Without Par Value |
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1,121,000 |
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Southern Power Company |
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Par Value $0.01 Per Share |
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1,000 |
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Documents incorporated by reference: specified portions of The Southern Companys Definitive Proxy
Statement on Schedule 14A relating to the 2011 Annual Meeting of Stockholders are incorporated by
reference into PART III. In addition, specified portions of the Definitive Information Statements
on Schedule 14C of Alabama Power Company, Georgia Power Company, and Mississippi Power Company
relating to each of their respective 2011 Annual Meetings of Shareholders are incorporated by
reference into PART III.
Southern Power Company meets the conditions set forth in General Instructions I(1)(a) and (b) of
Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in
General Instructions I(2)(b), (c), and (d) of Form 10-K.
This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia
Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company.
Information contained herein relating to any individual company is filed by such company on its own
behalf. Each company makes no representation as to information relating to the other companies.
DEFINITIONS
When used in Items 1 through 5 and Items 9A through 15, the following terms will have the
meanings indicated.
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Term |
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Meaning |
2010 ARP
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Alternative Rate Plan approved by
the Georgia PSC for Georgia Power for the years 2011 through 2013 |
AFUDC
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Allowance for Funds Used During Construction |
Alabama Power
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Alabama Power Company |
AMEA
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Alabama Municipal Electric Authority |
Clean Air Act
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Clean Air Act Amendments of 1990 |
Code
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Internal Revenue Code of 1986, as amended |
CPCN
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Certificate of Public Convenience and Necessity |
Dalton
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Dalton Utilities |
DOE
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United States Department of Energy |
Duke Energy
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Duke Energy Corporation |
ECCR
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Georgia Power Environmental Compliance Cost Recovery |
Energy Act of 1992
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Energy Policy Act of 1992 |
Energy Act of 2005
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Energy Policy Act of 2005 |
EPA
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United States Environmental Protection Agency |
FERC
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Federal Energy Regulatory Commission |
FMPA
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Florida Municipal Power Agency |
FP&L
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Florida Power & Light Company |
Georgia Power
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Georgia Power Company |
Gulf Power
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Gulf Power Company |
Hampton
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City of Hampton, Georgia |
IBEW
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International Brotherhood of Electrical Workers |
IGCC
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Integrated Coal Gasification Combined Cycle |
IIC
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Intercompany Interchange Contract |
IPP
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Independent Power Producer |
IRP
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Integrated Resource Plan |
IRS
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Internal Revenue Service |
Kemper IGCC
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IGCC facility under construction in Kemper County, Mississippi |
KUA
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Kissimmee Utility Authority |
MEAG Power
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Municipal Electric Authority of Georgia |
Mirant
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Mirant Corporation |
Mississippi Power
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Mississippi Power Company |
Moodys
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Moodys Investors Service |
NRC
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Nuclear Regulatory Commission |
OPC
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Oglethorpe Power Corporation |
OUC
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Orlando Utilities Commission |
power pool
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The operating arrangement whereby the integrated
generating resources of the traditional operating
companies and Southern Power are subject to joint
commitment and dispatch in order to serve their
combined load obligations |
PowerSouth
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PowerSouth Energy Cooperative (formerly, Alabama Electric Cooperative, Inc.) |
PPA
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Power Purchase Agreement |
Progress Energy Carolinas
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Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc. |
ii
DEFINITIONS
(continued)
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Term |
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Meaning |
Progress Energy Florida
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Florida Power Corporation, d/b/a Progress Energy Florida, Inc. |
PSC
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Public Service Commission |
registrants
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The Southern Company, Alabama Power
Company, Georgia Power Company, Gulf Power
Company, Mississippi Power Company, and
Southern Power Company |
RFP
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Request for Proposal |
RUS
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Rural Utilities Service (formerly Rural Electrification Administration) |
S&P
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Standard & Poors, a division of The
McGraw-Hill Companies |
SCS
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Southern Company Services, Inc. (the system
service company) |
SEC
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Securities and Exchange Commission |
SEGCO
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Southern Electric Generating Company |
SEPA
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Southeastern Power Administration |
SERC
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Southeastern Electric Reliability Council |
SMEPA
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South Mississippi Electric Power Association |
Southern Company
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The Southern Company |
Southern Company system
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Southern Company, the traditional operating
companies, Southern Power, SEGCO, Southern
Nuclear, SCS, SouthernLINC Wireless, and
other subsidiaries |
Southern Holdings
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Southern Company Holdings, Inc. |
SouthernLINC Wireless
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Southern Communications Services, Inc. |
Southern Nuclear
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Southern Nuclear Operating Company, Inc. |
Southern Power
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Southern Power Company |
Southern Renewable Energy
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Southern Renewable Energy, Inc. |
Stone & Webster
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Stone & Webster, Inc. |
traditional operating companies
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Alabama Power Company, Georgia Power
Company, Gulf Power Company, and
Mississippi Power Company |
TVA
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Tennessee Valley Authority |
Westinghouse
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Westinghouse Electric Company LLC |
iii
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements. Forward-looking
statements include, among other things, statements concerning the strategic goals for the wholesale
business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate
actions, environmental regulations and expenditures, future earnings, dividend payout ratios,
access to sources of capital, projections for the qualified pension, postretirement benefit, and
nuclear decommissioning trust fund contributions, financing activities, start and completion of
construction projects, plans and estimated costs for new generation resources, impact of the
American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of
the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance
Reauthorization, and Job Creation Act of 2010, 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:
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the impact of recent and future federal and state regulatory changes, including legislative
and regulatory initiatives regarding deregulation and restructuring of the electric utility
industry, implementation of the Energy Policy Act of 2005, environmental laws including
regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen,
carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other
substances, financial reform legislation, 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; |
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current and future litigation, regulatory investigations, proceedings, or inquiries,
including the pending EPA civil actions against certain Southern Company subsidiaries, FERC
matters, and IRS audits; |
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the effects, extent, and timing of the entry of additional competition in the markets in
which Southern Companys subsidiaries operate; |
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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; |
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available sources and costs of fuels; |
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ability to control costs and avoid cost overruns during the development and construction of
facilities; |
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investment performance of Southern Companys employee benefit plans and nuclear
decommissioning trust funds; |
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advances in technology; |
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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; |
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regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia
PSC and NRC approvals and potential DOE loan guarantees; |
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regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC
approvals and potential DOE loan guarantees; |
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the performance of projects undertaken by the non-utility businesses and the success of
efforts to invest in and develop new opportunities; |
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internal restructuring or other restructuring options that may be pursued; |
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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; |
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the ability of counterparties of Southern Company and its subsidiaries to make payments as
and when due and to perform as required; |
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the ability to obtain new short- and long-term contracts with wholesale customers; |
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the direct or indirect effect on Southern Companys business resulting from terrorist
incidents and the threat of terrorist incidents; |
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interest rate fluctuations and financial market conditions and the results of financing
efforts, including Southern Companys and its subsidiaries credit ratings; |
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the ability of Southern Company and its subsidiaries to obtain additional generating
capacity at competitive prices; |
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catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts,
pandemic health events such as influenzas, or other similar occurrences; |
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the direct or indirect effects on Southern Companys business resulting from incidents
affecting the U.S. electric grid or operation of generating resources; |
iv
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the effect of accounting pronouncements issued periodically by standard setting bodies; and |
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other factors discussed elsewhere herein and in other reports filed by the registrants from
time to time with the SEC. |
The registrants expressly disclaim any obligation to update any forward-looking statements.
v
PART I
Item 1. BUSINESS
Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern
Company is domesticated under the laws of Georgia and is qualified to do business as a foreign
corporation under the laws of Alabama. Southern Company owns all of the outstanding common stock
of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating
public utility company. The traditional operating companies supply electric service in the states
of Alabama, Georgia, Florida, and Mississippi. More particular information relating to each of the
traditional operating companies is as follows:
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Alabama Power is a corporation organized under the laws of the State of Alabama on November 10,
1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company, and
Houston Power Company. The predecessor Alabama Power Company had been in continuous existence
since its incorporation in 1906. |
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Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930 and was
admitted to do business in Alabama on September 15, 1948. |
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Gulf Power is a Florida corporation that has had a continuous existence since it was originally
organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to
do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia
on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under
the laws of the State of Florida on November 2, 2005. |
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Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972,
was admitted to do business in Alabama on November 28, 1972, and effective December 21, 1972, by
the merger into it of the predecessor Mississippi Power Company, succeeded to the business and
properties of the latter company. The predecessor Mississippi Power Company was incorporated
under the laws of the State of Maine on November 24, 1924 and was admitted to do business in
Mississippi on December 23, 1924 and in Alabama on December 7, 1962. |
In addition, Southern Company owns all of the common stock of Southern Power, which is also an
operating public utility company. Southern Power constructs, acquires, owns, and manages
generation assets and sells electricity at market-based rates in the wholesale market. Southern
Power is a corporation organized under the laws of Delaware on January 8, 2001 and was admitted to
do business in the States of Alabama, Florida, and Georgia on January 10, 2001, in the State of
Mississippi on January 30, 2001, and in the State of North Carolina on February 19, 2007.
Southern Company also owns all of the outstanding common stock or membership interests of
SouthernLINC Wireless, Southern Nuclear, SCS, Southern Holdings, Southern Renewable Energy, and
other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless
communications for use by Southern Company and its subsidiary companies and markets these services
to the public and also provides wholesale fiber optic solutions to telecommunication providers in
the Southeast. Southern Nuclear operates and provides services to Alabama Powers and Georgia
Powers nuclear plants and is currently developing new nuclear generation at Plant Vogtle. SCS is
the system service company providing, at cost, specialized services to Southern Company and its
subsidiary companies. Southern Holdings is an intermediate holding subsidiary for Southern
Companys investments in leveraged leases. Southern Renewable Energy was formed in January 2010 to
construct, acquire, own, and manage renewable generation assets.
Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an
operating public utility company that owns electric generating units with an aggregate capacity of
1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power
and Georgia Power are each entitled to one-half of SEGCOs capacity and energy. Alabama Power acts
as SEGCOs agent in the operation of SEGCOs units and furnishes coal to SEGCO as fuel for its
units. SEGCO also owns one 230,000 volt transmission line extending from Plant Gaston to the
Georgia state line at which point connection is made with the Georgia Power transmission line system.
I-1
Southern Companys segment information is included in Note 12 to the financial statements of
Southern Company in Item 8 herein.
The registrants Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K, and all amendments to those reports are made available on Southern Companys website,
free of charge, as soon as reasonably practicable after such material is electronically filed with
or furnished to the SEC. Southern Companys internet address is www.southerncompany.com.
The Southern Company System
Traditional Operating Companies
The traditional operating companies own generation, transmission, and distribution facilities. See
PROPERTIES in Item 2 herein for additional information on the traditional operating companies
generating facilities. Each companys transmission facilities are connected to the respective
companys own generating plants and other sources of power (including certain generating plants
owned by Southern Power) and are interconnected with the transmission facilities of the other
traditional operating companies and SEGCO. For information on the State of Georgias integrated
transmission system, see Territory Served by the Traditional Operating Companies and Southern
Power herein.
Agreements in effect with principal neighboring utility systems provide for capacity and energy
transactions that may be entered into from time to time for reasons related to reliability or
economics. Additionally, the traditional operating companies have entered into voluntary
reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group, and TVA and with Progress Energy Carolinas, Duke Energy, South Carolina
Electric & Gas Company, and Virginia Electric and Power Company, each of which provides for the
establishment and periodic review of principles and procedures for planning and operation of
generation and transmission facilities, maintenance schedules, load retention programs, emergency
operations, and other matters affecting the reliability of bulk power supply. The traditional
operating companies have joined with other utilities in the Southeast (including some of those
referred to above) to form the SERC to augment further the reliability and adequacy of bulk power
supply. Through the SERC, the traditional operating companies are represented on the National
Electric Reliability Council.
The utility assets of the traditional operating companies and certain utility assets of Southern
Power are operated as a single integrated electric system, or power pool, pursuant to the IIC.
Activities under the IIC are administered by SCS, which acts as agent for the traditional operating
companies and Southern Power. The fundamental purpose of the power pool is to provide for the
coordinated operation of the electric facilities in an effort to achieve the maximum possible
economies consistent with the highest practicable reliability of service. Subject to service
requirements and other operating limitations, system resources are committed and controlled through
the application of centralized economic dispatch. Under the IIC, each traditional operating
company and Southern Power retains its lowest cost energy resources for the benefit of its own
customers and delivers any excess energy to the power pool for use in serving customers of other
traditional operating companies or Southern Power or for sale by the power pool to third parties.
The IIC provides for the recovery of specified costs associated with the affiliated operations
thereunder, as well as the proportionate sharing of costs and revenues resulting from power pool
transactions with third parties.
Southern Company, each traditional operating company, Southern Power, Southern Nuclear, SEGCO, and
other subsidiaries have contracted with SCS to furnish, at direct or allocated cost and upon
request, the following services: general and design engineering, operations, purchasing,
accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and
pension administration, human resources, systems and procedures, digital wireless communications,
and other services with respect to business and operations and power pool transactions. Southern
Power and SouthernLINC Wireless have also secured from the traditional operating companies certain
services which are furnished at cost and, in the case of Southern Power, which are subject to FERC
regulations, in compliance with such regulations.
I-2
Alabama Power and Georgia Power each have a contract with Southern Nuclear to operate Plant Farley
and Plants Hatch and Vogtle, respectively. In addition, Georgia Power has a contract with Southern
Nuclear to develop, license, construct, and operate additional generating units at Plant Vogtle.
See Regulation Nuclear Regulation herein for additional information.
Southern Power
Southern Power is an electric wholesale generation subsidiary with market-based rate authority from
the FERC. Southern Power constructs, acquires, owns, and manages generation assets and sells
electricity at market-based prices in the wholesale market. Southern Powers business activities
are not subject to traditional state regulation like the traditional operating companies but are
subject to regulation by the FERC. Southern Power has attempted to insulate itself from
significant fuel supply, fuel transportation, and electric transmission risks by making such risks
the responsibility of the counterparties to its PPAs. However, Southern Powers future earnings
will depend on the parameters of the wholesale market, federal regulation, and the efficient
operation of its wholesale generating assets. For additional information on Southern Powers
business activities, see MANAGEMENTS DISCUSSION AND ANALYSIS OVERVIEW Business Activities
of Southern Power in Item 7 herein.
In 2008, Southern Power completed construction on Plant Franklin Unit 3 which added 659 megawatts
to the Southern Company system generating capacity. Southern Power is constructing a 720-megawatt
electric generating plant in Cleveland County, North Carolina. This new plant is expected to go
into commercial operation in 2012. The total estimated construction cost is expected to be between
$350 million and $400 million.
In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches
Power LLC from American Renewables LLC, the original developer of a biomass project in Sacul,
Texas. Southern Power continues to construct the Nacogdoches biomass generating plant with an
estimated capacity of 100 megawatts. The generating plant will be fueled from wood waste and is
expected to begin commercial operation in 2012. The total estimated cost of the project is
expected to be between $475 million and $500 million.
In December 2009, Southern Power acquired all of the outstanding membership interests of West
Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC, an affiliate of LS
Power. West Georgia was merged into Southern Power as of the acquisition date and Southern Power
now owns a dual-fueled generating plant near Thomaston, Georgia with nameplate capacity of
approximately 669 megawatts. The plant consists of four combustion turbine natural gas generating
units with oil back-up.
As of December 31, 2010, Southern Power had 7,880 megawatts of nameplate capacity in commercial
operation.
Other Businesses
Southern Holdings is an intermediate holding subsidiary for Southern Companys investments in
leveraged leases.
SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its
subsidiary companies and markets its services to non-affiliates within the Southeast. SouthernLINC
Wireless delivers multiple wireless communication options including push to talk, cellular service,
text messaging, wireless internet access, and wireless data. Its system covers approximately
127,000 square miles in the Southeast. SouthernLINC Wireless also provides wholesale fiber optic
solutions to telecommunication providers in the Southeast under the name Southern Telecom.
On January 25, 2010, Southern Renewable Energy was formed to construct, acquire, own, and manage
renewable generation assets. On March 12, 2010, Southern Renewable Energy and Turner Renewable
Energy acquired from First Solar, Inc. the Cimarron project, a 30-megawatt solar photovoltaic plant
near Cimarron, New Mexico. On November 25, 2010, the Cimarron plant began commercial operation.
These efforts to invest in and develop new business opportunities offer potential returns exceeding
those of rate-regulated operations. However, these activities also involve a higher degree of
risk.
I-3
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs
to accommodate existing and estimated future loads on their respective systems. For estimated
construction and environmental expenditures for the periods 2011 through 2013, see Note 7 to the
financial statements of Southern Company and each traditional operating company under Construction
Program and Note 7 to the financial statements of Southern Power under Expansion Program in Item
8 herein. Base level estimated construction costs in 2011 are expected to be apportioned
approximately as follows: (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern |
|
|
|
|
|
|
|
|
|
|
|
|
Company |
|
Alabama |
|
Georgia |
|
Gulf |
|
Mississippi |
|
Southern |
|
|
System * |
|
Power |
|
Power |
|
Power |
|
Power |
|
Power |
|
|
|
New Generation |
|
$ |
2,171 |
|
|
$ |
|
|
|
$ |
934 |
|
|
$ |
|
|
|
$ |
665 |
|
|
$ |
572 |
|
Environmental ** |
|
|
341 |
|
|
|
47 |
|
|
|
73 |
|
|
|
176 |
|
|
|
45 |
|
|
|
|
|
Transmission & Distribution Growth |
|
|
530 |
|
|
|
123 |
|
|
|
349 |
|
|
|
39 |
|
|
|
20 |
|
|
|
|
|
Maintenance (Generation,
Transmission & Distribution) |
|
|
1,270 |
|
|
|
532 |
|
|
|
489 |
|
|
|
154 |
|
|
|
79 |
|
|
|
|
|
Nuclear fuel |
|
|
299 |
|
|
|
129 |
|
|
|
170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
General plant |
|
|
278 |
|
|
|
86 |
|
|
|
95 |
|
|
|
12 |
|
|
|
9 |
|
|
|
27 |
|
|
|
|
Total *** |
|
$ |
4,889 |
|
|
$ |
917 |
|
|
$ |
2,110 |
|
|
$ |
381 |
|
|
$ |
818 |
|
|
$ |
599 |
|
|
|
|
|
|
|
* |
|
These amounts include the traditional operating companies and Southern Power (as detailed in
the table above) as well as the amounts for the other subsidiaries. See Other Businesses
herein for additional information. |
|
** |
|
These amounts reflect estimated capital expenditures in 2011 to comply with existing statutes
and regulations. In addition, each of Southern Company and the traditional operating
companies has estimated of a range of potential incremental investments to comply with
proposed environmental regulations. These additional estimated amounts for 2011 are: from $74
million to $289 million for the Southern Company system; up to $48 million for Alabama Power;
from $69 million to $289 million for Georgia Power; and up to $17 million for Gulf Power.
Mississippi Power and Southern Power have no anticipated incremental
investments to comply with anticipated new environmental regulation in 2011. |
|
*** |
|
The estimated 2011 total for Southern Power includes cash
payments for long-term service agreements. |
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 generating plants, including unit retirement and replacement decisions, 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; storm impacts; and the cost of capital. In addition, there can be no assurance
that costs related to capital expenditures will be fully recovered.
See Regulation Environmental Statutes and Regulations herein for additional information with
respect to certain existing and proposed environmental requirements and PROPERTIES
Jointly-Owned Facilities in Item 2 herein for additional information concerning Alabama Powers,
Georgia Powers, and Southern Powers joint ownership of certain generating units and related
facilities with certain non-affiliated utilities.
Financing Programs
See each of the registrants MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND
LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8
herein for information concerning financing programs.
I-4
Fuel Supply
The traditional operating companies and SEGCOs supply of electricity is derived mainly from
coal. Southern Powers supply of electricity is primarily fueled by natural gas. See MANAGEMENTS
DISCUSSION AND ANALYSIS RESULTS OF OPERATION Fuel and Purchased Power Expenses of Southern
Company and each traditional operating company in Item 7 herein for information regarding the
electricity generated and the average cost of fuel in cents per net kilowatt-hour generated for the
years 2008 through 2010.
The traditional operating companies have agreements in place from which they expect to receive
approximately 97.5% of their coal burn requirements in 2011. These agreements have terms ranging
between one and eight years. In 2010, the weighted average sulfur content of all coal burned by
the traditional operating companies was 0.78% sulfur. This sulfur level, along with banked and
purchased sulfur dioxide allowances, allowed the traditional operating companies to remain within
limits set by Phase I of the Clean Air Interstate Rule under the Clean Air Act. In 2010, the
Southern Company system purchased approximately 35,000 tons of sulfur dioxide allowances, 6,650
tons of annual nitrogen oxide emissions allowances, and 2,100 tons of seasonal nitrogen oxide
emission allowances to be used in current and future periods. As additional environmental
regulations are proposed that impact the utilization of coal, the traditional operating companies
fuel mix will be monitored to ensure that the traditional operating companies remain in compliance
with applicable laws and regulations. Additionally, Southern Company and the traditional operating
companies will continue to evaluate the need to purchase additional emissions allowances, the
timing of capital expenditures for emissions control equipment, and potential unit retirements and
replacements. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL
Environmental Matters of Southern Company and each traditional operating company in Item 7 herein
for information on the Clean Air Act, water quality, coal combustion byproducts, and global climate
issues.
SCS, acting on behalf of the traditional operating companies and Southern Power, has agreements in
place for the natural gas burn requirements of the Southern Company system. For 2011, SCS has
contracted for 255 billion cubic feet of natural gas supply under agreements with remaining terms
up to 10 years. In addition to gas supply, SCS has contracts in place for both firm gas
transportation and storage. Management believes that these contracts provide sufficient natural
gas supplies, transportation, and storage to ensure normal operations of the Southern Company
systems natural gas generating units.
Changes in fuel prices to the traditional operating companies are generally reflected in fuel
adjustment clauses contained in rate schedules. See Rate Matters Rate Structure and Cost
Recovery Plans herein for additional information. Southern Powers PPAs generally provide that
the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have numerous contracts covering a portion of their nuclear fuel
needs for uranium, conversion services, enrichment services, and fuel fabrication. These contracts
have varying expiration dates and most of them are for less than 10 years. Management believes
that sufficient capacity for nuclear fuel supplies and processing exists to preclude the impairment
of normal operations of the Southern Company systems nuclear generating units.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that
provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent 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. See Note 3 to the financial
statements of Southern Company, Alabama Power, and Georgia Power under Nuclear Fuel Disposal
Costs in Item 8 herein for additional information.
Territory Served by the Traditional Operating Companies and Southern Power
The territory in which the traditional operating companies provide electric service comprises
most of the states of Alabama and Georgia together with the northwestern portion of Florida and
southeastern Mississippi. In this territory there are non-affiliated electric distribution systems
which obtain some or all of their power requirements either directly or indirectly from the
traditional operating companies. The territory has an area of approximately 120,000 square miles
and an estimated population of approximately 13 million. Southern Power sells electricity at
market-based prices in the wholesale market to investor-owned utilities, IPPs, municipalities, and
electric cooperatives.
I-5
Alabama Power is engaged, within the State of Alabama, in the generation and purchase of
electricity and the transmission, distribution, and sale of such electricity at retail in over 650
communities (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well
as in rural areas, and at wholesale to 15 municipally-owned electric distribution systems, 11 of
which are served indirectly through sales to AMEA, and two rural distributing cooperative
associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal
from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers
in promoting the sale of, electric appliances.
Georgia Power is engaged in the generation and purchase of electricity and the transmission,
distribution, and sale of such electricity within the State of Georgia at retail in over 600
communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as
in rural areas, and at wholesale currently to OPC, MEAG Power, Dalton, Hampton, and various
electric membership corporations.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation and purchase
of electricity and the transmission, distribution, and sale of such electricity at retail in 71
communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas,
and at wholesale to a non-affiliated utility and a municipality.
Mississippi Power is engaged in the generation and purchase of electricity and the transmission,
distribution, and sale of such electricity within 23 counties in southeastern Mississippi, at
retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and
Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric
distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to kilowatt-hour sales by customer classification for the traditional
operating companies, see MANAGEMENTS DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS of each
traditional operating company in Item 7 herein. Also, for information relating to the sources of
revenues for Southern Company, each traditional operating company, and Southern Power, reference is
made to Item 7 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to
provide electric service to customers in rural sections of the country. There are 71 electric
cooperative organizations operating in the territory in which the traditional operating companies
provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power
to several distributing cooperatives, municipal systems, and other customers in south Alabama and
northwest Florida. PowerSouth owns generating units with approximately 1,776 megawatts of
nameplate capacity, including an undivided 8.16% ownership interest in Alabama Powers Plant Miller
Units 1 and 2. PowerSouths facilities were financed with RUS loans secured by long-term contracts
requiring distributing cooperatives to take their requirements from PowerSouth to the extent such
energy is available.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving
interconnection between their respective systems. The delivery of capacity and energy from
PowerSouth to certain distributing cooperatives in the service areas of Alabama Power and Gulf
Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The
rates for this service to PowerSouth are on file with the FERC. See PROPERTIES Jointly-Owned
Facilities in Item 2 herein for details of Alabama Powers joint-ownership with PowerSouth of a
portion of Plant Miller.
Four electric cooperative associations, financed by the RUS, operate within Gulf Powers service
area. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal
power marketing agency). A non-affiliated utility also operates within Gulf Powers service area
and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with SMEPA, a generating and transmitting
cooperative, pursuant to which various services are provided, including the furnishing of
protective capacity by Mississippi Power to
I-6
SMEPA. On July 27, 2010, Mississippi Power and SMEPA entered into an asset purchase agreement
whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this
transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of
all construction permits, appropriate regulatory approvals, financing, and other conditions. On
December 2, 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC
requesting regulatory approval for SMEPAs 17.5% ownership of the Kemper IGCC.
There are also 65 municipally-owned electric distribution systems operating in the territory in
which the traditional operating companies provide electric service at retail or wholesale.
Forty-eight municipally-owned electric distribution systems and one county-owned system receive
their requirements through MEAG Power, which was established by a Georgia state statute in 1975.
MEAG Power serves these requirements from self-owned generation facilities, some of which are
jointly-owned with Georgia Power, power purchased from Georgia Power, and purchases from other
resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power.
Dalton serves its requirements from self-owned generation facilities, some of which are
jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power
through a service agreement. In addition, Georgia Power serves the full requirements of Hamptons
electric distribution system under a market-based contract. See PROPERTIES Jointly-Owned
Facilities in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission
Corporation (formerly OPCs transmission division), MEAG Power, and Dalton providing for the
establishment of an integrated transmission system to carry the power and energy of all parties.
The agreements require an investment by each party in the integrated transmission system in
proportion to its respective share of the aggregate system load. See PROPERTIES Jointly-Owned
Facilities in Item 2 herein for additional information.
Southern Power has PPAs with some of the traditional operating companies and with other
investor-owned utilities, IPPs, municipalities, and electric cooperatives. See MANAGEMENTS
DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Power Sales Agreements of Southern Power
in Item 7 herein for additional information concerning Southern Powers PPAs.
SCS, acting on behalf of the traditional operating companies, also has a contract with SEPA
providing for the use of the traditional operating companies facilities at government expense to
deliver to certain cooperatives and municipalities, entitled by federal statute to preference in
the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated
to them by SEPA from certain United States government hydroelectric projects.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued Grandfather Certificates of public
convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating
in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them
to distribute electricity in certain specified geographically described areas of the state. The
six cooperatives serve approximately 325,000 retail customers in a certificated area of
approximately 10,300 square miles. In areas included in a Grandfather Certificate, the utility
holding such certificate may, without further certification, extend its lines up to five miles;
other extensions within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas
included in such a certificate which are subsequently annexed to municipalities may continue to be
served by the holder of the certificate, irrespective of whether it has a franchise in the annexing
municipality. On the other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.
Competition
The electric utility industry in the United States is continuing to evolve as a result of
regulatory and competitive factors. Among the early primary agents of change was the Energy Act of
1992 which allowed IPPs to access a utilitys transmission network in order to sell electricity to
other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by
various factors,
I-7
including price, availability, technological advancements, service, and reliability. These factors
are, in turn, affected by, among other influences, regulatory, political, and environmental
considerations, taxation, and supply.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the
Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within
existing municipal limits were assigned to the primary electric supplier therein. Areas outside of
such municipal limits were either to be assigned or to be declared open for customer choice of
supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with
such standards, the Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, this Act provides that any new customer locating
outside of 1973 municipal limits and having a connected load of at least 900 kilowatts may exercise
a one-time choice for the life of the premises to receive electric service from the supplier of its
choice.
Generally, the traditional operating companies have experienced, and expect to continue to
experience, competition in their respective retail service territories in varying degrees as the
result of self-generation (as described below) by customers and other factors.
Southern Power competes with investor owned utilities, IPPs, and others for wholesale energy sales
primarily in the Southeastern United States wholesale market. The needs of this market are driven
by the demands of end users in the Southeast and the generation available. Southern Powers
success in wholesale energy sales is influenced by various factors including reliability and
availability of Southern Powers plants, availability of transmission to serve the demand, price,
and Southern Powers ability to contain costs.
Alabama Power currently has cogeneration contracts in effect with 10 industrial customers. Under
the terms of these contracts, Alabama Power purchases excess generation of such companies. During
2010, Alabama Power purchased approximately 194 million kilowatt-hours from such companies at a
cost of $8.2 million.
Georgia Power currently has contracts in effect with 11 small power producers whereby Georgia Power
purchases their excess generation. During 2010, Georgia Power purchased 45 million kilowatt-hours
from such companies at a cost of $1.6 million. Georgia Power has PPAs for electricity with two
cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity
output. During 2010, Georgia Power purchased 178 million kilowatt-hours at a cost of $27.7 million
from these facilities.
Also during 2010, Georgia Power purchased energy from eight customer-owned generating facilities.
Seven of the eight customers provide only energy to Georgia Power. These seven customers make no
capacity commitment and are not dispatched by Georgia Power. Georgia Power does have a contract
with the remaining customer for eight megawatts of dispatchable capacity and energy. During 2010,
Georgia Power purchased a total of 49 million kilowatt-hours from the eight customers at a cost of
approximately $1.9 million.
Gulf Power currently has agreements in effect with various industrial, commercial, and qualifying
facilities pursuant to which Gulf Power purchases as available energy from customer-owned
generation. During 2010, Gulf Power purchased 111.7 million kilowatt-hours from such companies for
approximately $6.3 million.
Mississippi Power currently has a cogeneration agreement in effect with one of its industrial
customers. Under the terms of this contract, Mississippi Power purchases any excess generation.
During 2010, Mississippi Power did not purchase any excess generation from this customer.
Seasonality
The demand for electric power generation is affected by seasonal differences in the weather.
At the traditional operating companies and Southern Power, the demand for power peaks during the
summer months, with market prices reflecting the demand of power and available generating resources
at that time. Power demand peaks can also be recorded during the winter. As a result, the overall
operating results of Southern Company, the traditional operating companies, and Southern Power in
the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the
traditional operating companies, and Southern Power have historically sold less power when weather
conditions are milder.
I-8
Regulation
State Commissions
The traditional operating
companies are subject to the jurisdiction of their respective state PSCs.
The PSCs have broad powers of supervision and regulation over public utilities operating in the
respective states, including their rates, service regulations, sales of securities (except for the
Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail
service territories. See Territory Served by the Traditional Operating Companies and Southern
Power and Rate Matters herein for additional information.
Federal Power Act
The traditional operating companies,
Southern Power and its generation subsidiaries, SEGCO, and
Southern Renewable Energys generation subsidiary are all public utilities engaged in
wholesale sales of energy in interstate commerce and therefore are subject to the rate, financial,
and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain
financings and allows an at cost standard for services rendered by system service companies such
as SCS. The FERC is also authorized to establish regional reliability organizations which are
authorized to enforce reliability standards, to address impediments to the construction of
transmission, and to prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the
earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric
developments. Among the hydroelectric projects subject to licensing by the FERC are 14 existing
Alabama Power generating stations having an aggregate installed capacity of 1,662,400 kilowatts and
18 existing Georgia Power generating stations having an aggregate installed capacity of 1,087,296
kilowatts.
In July 2005, Alabama Power filed two applications with the FERC for new 50-year licenses for its
seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell,
Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on the Warrior River. The
FERC licenses for all of these nine developments expired in July and August 2007. Since the FERC
did not act on any of the new license applications prior to the expiration of the existing
licenses, the FERC is required by law to issue annual licenses under the terms and conditions of
the existing licenses, until action is taken on the new license applications. The FERC issued an
annual license to the Coosa developments in August 2007, which was automatically renewed in 2008,
2009, and 2010. On March 31, 2010, the FERC issued a new 30-year license for the Lewis Smith and
Bankhead developments on the Warrior River. The new license authorizes Alabama Power to continue
operating these facilities in a manner consistent with past operations. On April 30, 2010, a
stakeholders group filed a request for rehearing of the FERC order issuing the new license. On May
27, 2010, the FERC granted the rehearing request for the limited purpose of allowing the FERC
additional time to consider the substantive issues in the request.
In 2006, Alabama Power initiated the process of developing an application to relicense the Martin
hydroelectric project located on the Tallapoosa River. The current Martin license will expire in
2013 and the application for a new license is expected to be filed with the FERC in 2011. In 2010,
Alabama Power initiated the process of developing an application to relicense the Holt
hydroelectric project located on Warrior River. The current Holt license will expire in August
2015 and the application for a new license is expected to be filed prior to that time.
In 2007, Georgia Power began the relicensing process for Bartletts Ferry which is located on the
Chattahoochee River near Columbus, Georgia. The current Bartletts Ferry license expires in 2014
and the application for a new license is expected to be submitted to the FERC in 2012.
The ultimate outcome of these matters cannot be determined at this time. See MANAGEMENTS
DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL FERC Matters of Alabama Power in Item 7
herein for additional information.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure
pumped storage facility of 847,800 kilowatt capacity. See PROPERTIES Jointly-Owned Facilities
in Item 2 herein for additional information.
I-9
Licenses for all projects, excluding those discussed above, expire in the period 2023-2034 in the
case of Alabama Powers projects and in the period 2020-2039 in the case of Georgia Powers
projects.
Upon or after the expiration of each license, the United States Government, by act of Congress, may
take over the project or the FERC may relicense the project either to the original licensee or to a
new licensee. In the event of takeover or relicensing to another, the original licensee is to be
compensated in accordance with the provisions of the Federal Power Act, such compensation to
reflect the net investment of the licensee in the project, not in excess of the fair value of the
property, plus reasonable damages to other property of the licensee resulting from the severance
therefrom of the property.
Nuclear Regulation
Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC
is responsible for licensing and regulating nuclear facilities and materials and for conducting
research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act
of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear
Nonproliferation Act of 1978; and in accordance with the National Environmental Policy Act of 1969,
as amended, and other applicable statutes. These responsibilities also include protecting public
health and safety, protecting the environment, protecting and safeguarding nuclear materials and
nuclear power plants in the interest of national security, and assuring conformity with antitrust
laws.
In January 2002, the NRC extended the licenses of Georgia Powers Plant Hatch Units 1 and 2 until
2034 and 2038, respectively. In May 2005, the NRC extended the licenses of Alabama Powers Plant
Farley Units 1 and 2 until 2037 and 2041, respectively. In June 2009, the NRC extended the
licenses of Plant Vogtle Units 1 and 2 to 2047 and 2049, respectively.
In August 2009, the NRC issued an Early Site Permit and Limited Work Authorization to Southern
Nuclear, on behalf of Georgia Power, OPC, MEAG Power, and City of Dalton (collectively, Owners),
related to two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4).
In March 2008, Southern Nuclear filed an application with the NRC for a combined construction and
operating license (COL) for Plant Vogtle Units 3 and 4, which, if licensed by the NRC, are scheduled to
be placed in service in 2016 and 2017, respectively.
Georgia Power currently expects to receive the Vogtle 3 and 4
COLs from the NRC in late 2011 based on the NRCs February 16,
2011 release of its COL schedule framework.
See MANAGEMENTS DISCUSSION AND ANALYSIS
FUTURE EARNINGS POTENTIAL Construction Nuclear of Georgia Power in Item 7 herein and Note 3
to the financial statements of Southern Company under Retail Regulatory Matters Georgia Power -
Nuclear Construction and Georgia Power under Construction Nuclear in Item 8 herein for
additional information.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power
in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
Environmental Statutes and Regulations
Southern Companys 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. Compliance with these existing environmental
requirements involves significant capital and operating costs, a major portion of which is expected
to be recovered through existing ratemaking provisions or market-based rates for Southern Power.
There is no assurance, however, that all such costs will be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to
be, a significant focus for Southern Company, each traditional operating company, Southern Power,
and SEGCO. In addition, existing environmental laws and regulations may be changed or new laws and
regulations may be adopted or otherwise become applicable to Southern Company, the traditional
operating companies, Southern Power, or SEGCO, including laws and regulations designed to address
global climate change, air quality, water quality, management of waste materials and coal
combustion byproducts, including coal ash, or other environmental, public health, and welfare
concerns. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental
Matters of Southern Company and each of the traditional operating companies in
I-10
Item 7 herein for additional information about the Clean Air Act and other environmental issues,
including, but not limited to, the litigation brought by the EPA under the New Source Review
provisions of the Clean Air Act, possible additional and/or revised regulations related to air and
water quality, possible climate change legislation and regulation, and possible regulation of coal
combustion byproducts. Also see MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL
Environmental Matters of Southern Power in Item 7 herein for information about environmental
issues, possible climate change legislation and regulation and possible regulation of coal
combustion byproducts.
Southern Company, the traditional operating companies, Southern Power, and SEGCO are unable to
predict at this time what additional steps they may be required to take as a result of the
implementation of existing or future requirements pertaining to climate change, air quality, water
quality, and management of waste materials and coal combustion byproducts, including coal ash, but
such steps could adversely affect system operations and result in substantial additional costs.
For example, potential regulations relating to air quality could require the installation of
additional environmental controls, potential regulations relating to water quality could require
the installation of cooling towers at certain existing generating units, and potential regulations
relating to coal combustion byproducts could require closure of or significant change to existing
storage units and construction of lined landfills, as well as additional waste management and
groundwater monitoring requirements.
Depending on the final outcome of the wide range of proposed environmental regulations currently
under consideration by the EPA, the retirement and replacement of certain existing generating units
may be more economically efficient than installing required controls necessary to remain in
compliance. In addition, while the outcome of these matters cannot now be determined, potential
additional environmental regulations could result in delays in obtaining appropriate licenses for
generating facilities, increased construction and operating costs, or reduced generation, the
nature and extent of which, while not determinable at this time, could be substantial. See
Construction Program herein for additional information.
Rate Matters
Rate Structure and Cost Recovery Plans
The rates and service regulations of the traditional operating companies are uniform for each class
of service throughout their respective service areas. Rates for residential electric service are
generally of the block type based upon kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for commercial service are
presently of the block type and, for large customers, the billing demand is generally used to
determine capacity and minimum bill charges. These large customers rates are generally based upon
usage by the customer and include rates with special features to encourage off-peak usage.
Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their
respective state PSCs to negotiate the terms and cost of service to large customers. Such terms
and cost of service, however, are subject to final state PSC approval.
Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions at
the traditional operating companies. These fuel cost recovery provisions are adjusted to reflect
increases or decreases in such costs as needed. Gulf Powers and Mississippi Powers fuel cost
recovery provisions are adjusted annually to reflect increases or decreases in such costs. Georgia
Power is currently required to file its next fuel case by March 1, 2011, with a new rate to be effective June
1, 2011. Alabama Powers fuel cost recovery rates are adjusted
as required; a new rate
is scheduled to be effective on April 1, 2011. Revenues are adjusted for differences between
recoverable costs and amounts actually recovered in current rates.
Approved environmental compliance and storm damage costs are recovered at Alabama Power and
Mississippi Power through cost recovery provisions approved by their respective state PSCs. Within
limits approved by their respective PSCs, these rates are adjusted to reflect increases or
decreases in such costs as required.
Georgia Powers environmental compliance costs are recovered through its ECCR tariff. On December
21, 2010, the Georgia PSC voted to approve the 2010 ARP effective January 1, 2011 and continuing
through December 31, 2013 under which the ECCR tariff has been continued. See Note 3 to the
financial statements of Southern Company
I-11
under Retail Regulatory Matters Georgia Power Retail Rate Plans and Georgia Power under
Retail Regulatory Matters Rate Plans in Item 8 herein for additional information.
See Integrated Resource Planning herein for a discussion of Georgia PSC certification of new
demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENTS DISCUSSION
AND ANALYSIS FUTURE EARNINGS POTENTIAL Construction Nuclear of Georgia Power in Item 7
herein and Note 3 to the financial statements of Southern Company under Retail Regulatory Matters
Georgia Power Nuclear Construction and Georgia Power under Construction Nuclear in Item
8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC
certification of Plant Vogtle Units 3 and 4, which allow Georgia Power to recover financing costs
for construction of the new nuclear units during the construction period beginning in 2011. On
December 21, 2010, as a part of the 2010 ARP, the Georgia PSC approved Georgia Powers Nuclear
Construction Cost Recovery tariff effective January 1, 2011.
Alabama Power recovers the cost of certificated new plant and purchased power capacity through cost
recovery provisions which are approved annually. Gulf Power files a rate clause request annually
with the Florida PSC to recover costs associated with purchased power capacity, energy
conservation, and environmental compliance. Revenues are adjusted for differences between
recoverable costs and amounts actually recovered in current rates.
See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL PSC Matters of Southern
Company and each of the traditional operating companies in Item 7 herein and Note 3 to the
financial statements of Southern Company under Retail Regulatory Matters and Note 3 to the
financial statements of each of the traditional operating companies under Retail Regulatory
Matters in Item 8 herein for a discussion of rate matters. Also, see Note 1 to the financial
statements of Southern Company and each of the traditional operating companies in Item 8 herein for
a discussion of recovery of fuel costs, storm damage costs, and environmental compliance costs
through rates.
The traditional operating companies,
Southern Power and its generation subsidiaries, and Southern Renewable
Energys generation subsidiary are authorized
by 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.
Integrated Resource Planning
Each of the traditional operating companies continually evaluates its electric generating resources
in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the
existing and future demand requirements of its customers. See Environmental Statutes and
Regulations above for a discussion of existing and potential environmental regulations that may
impact the future generating resource needs of the traditional operating companies.
Certain of the traditional operating companies periodically file IRPs with their respective state
PSC. The following is a summary of the most recent IRP filings by certain of the traditional
operating companies.
Georgia Power
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to
meet the future electrical needs of its customers through a combination of demand-side and
supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or
supply-side resources for Georgia Power to get cost recovery. Once certified, the lesser of actual
or certified construction costs and purchased power costs is recoverable through rates.
On January 29, 2010, Georgia Power filed its 2010 IRP with the Georgia PSC. The 2010 IRP projected
that Georgia Powers current supply-side and demand-side resources are sufficient to provide a
cost-effective and reliable source of capacity and energy at least through 2014. The 2010 IRP
identified a number of potential new or modified federal environmental statutes and regulations
that could significantly impact Georgia Powers existing coal-fired generating units. In addition,
under the State of Georgias Multi-Pollutant Rule, Georgia Power is required to install specific
emissions controls on certain coal-fired generating units by specific dates between December 31,
2008 and June 1, 2015. See Environmental Statutes and Regulations above.
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On July 6, 2010, the Georgia PSC approved Georgia Powers 2010 IRP including the following
provisions: (1) restarting an RFP to enable the potential replacement of coal units that may be
retired beginning in approximately 2015; (2) expanding energy efficiency efforts; (3) implementing
seven new demand-side management and energy efficiency programs; (4) collecting incentives totaling
10% of the net benefit of energy efficiency programs annually, with certain conditions, for the
certified programs; (5) developing a one megawatt self-build portfolio of solar photovoltaic
demonstration projects; (6) delaying capital spending on the conversion of Plant Mitchell Unit 3
from a coal-fired generating unit to a renewable biomass generating unit until the EPA issues
applicable maximum achievable control technology (MACT) standards under the Clean Air Act; (7)
considering conversion of additional coal units to biomass, if such conversions appear to be
economic and feasible; and (8) continuing to suspend work on environmental controls for Units 6 and
7 at Plant Yates and Units 1 and 2 at Plant Branch until the EPA issues applicable MACT standards
and regulations for coal combustion byproducts.
In addition, Georgia Powers 2010 IRP reflected the construction of Plant McDonough Units 4, 5, and
6 (natural gas) and Plant Vogtle Units 3 and 4 (nuclear) as certified by the Georgia PSC in 2007
and 2009, respectively. In addition, the 2010 IRP also reflected the related retirement of Plant
McDonough Units 1 and 2 (coal), which were decertified by the Georgia PSC in connection with
construction of the new units. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS
POTENTIAL Construction of Georgia Power in Item 7 herein and Note 3 to the financial
statements of Southern Company under Retail Regulatory Matters Georgia Power Nuclear
Construction and Retail Regulatory Matters Georgia Power Other Construction in Item 8
herein and Note 3 to the financial statements of Georgia Power under Construction in Item 8
herein for additional information
Georgia Power currently expects to file an update to its IRP in June 2011. Georgia Power is
continuing to analyze the potential costs and benefits of installing environmental controls on its
remaining coal-fired generating units in light of the potential new or modified environmental
regulations. As contemplated in the 2010 IRP, Georgia Power may determine that retiring and
replacing certain of these existing units with new generating resources or purchased power is more
economically efficient than installing the required environmental controls. On April 20, 2010,
Georgia Power issued an RFP for approximately 1,000 megawatts to assure a reliable and economic
supply in the event replacement capacity is needed and is currently negotiating with counterparties
that offered the most competitive proposals. Certification of any needed resources procured
through the RFP would be expected by approximately February 2012.
Under the terms of Georgia Powers 2010 ARP, any costs associated with changes to Georgia Powers
approved environmental operating or capital budgets (resulting from new or revised environmental
regulations) through 2013 that are approved by the Georgia PSC in connection with Georgia Powers
updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed
appropriate by the Georgia PSC. Such costs that may be deferred as a regulatory asset include any
impairment losses that may result from a decision to retire certain units that are no longer cost
effective in light of new or modified environmental regulations. In addition, in connection with
Georgia Powers 2010 ARP, the Georgia PSC also approved revised depreciation rates that will
recover the remaining book value of certain of Georgia Powers existing coal-fired units by
December 31, 2014.
In addition, Georgia Power expects to file a request with the Georgia PSC in spring 2011 for the
certification of 562 megawatts of certain wholesale capacity that will be returned to retail
service on January 1, 2015 (312 megawatts) and April 1, 2016 (250 megawatts). On September 20,
2010, the Georgia PSC accepted Georgia Powers offer to return this generating capacity to retail
service.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf
Powers estimate of its power-generating needs in the period and the general location of its
proposed power plant sites. The 10-year site plans submitted by the states electric utilities are
reviewed by the Florida PSC and subsequently classified as either suitable or unsuitable. The
Florida PSC then reports its findings along with any suggested revisions to the Florida Department
of Environmental Protection for its consideration at any subsequent electrical
I-13
power plant site certification proceedings. Under Florida law, any 10-year site plans submitted by
an electric utility are considered tentative information for planning purposes only and may be
amended at any time at the discretion of the utility with written notification to the Florida PSC.
At least every five years, the Florida PSC must conduct proceedings to establish numerical goals
for all investor-owned electric utilities and certain municipal or cooperative electric utilities
in the state to reduce the growth rates of weather-sensitive peak demand, to reduce and control the
growth rates of electric consumption, and to increase the conservation of expensive resources, such
as petroleum fuels. Overall residential kilowatts and kilowatt hours goals and overall
commercial/industrial kilowatt and kilowatt hours goals for each utility are set by the Florida PSC
for each year over a 10-year period. The goals are to be based on an estimate of the total cost
effective kilowatts and kilowatt hours savings reasonably achievable through demand-side management
in each utilitys service area over a 10-year period. Once goals have been set, each affected
utility must develop and submit plans and programs to meet the overall goals within its service
area to the Florida PSC for review and approval. Once approved, the utilities are required to
submit periodic reports which the Florida PSC then uses to prepare its annual report to the
Governor and Legislature of the goals that have been established and the progress towards meeting
those goals.
Gulf Powers most recent 10-year site plan was classified by the Florida PSC as suitable in
December 2010. Gulf Powers most recent 10-year site plan and environmental compliance plan
identify potential environmental regulations relating to maximum achievable control technology for
hazardous air pollutants and potential legislation or regulation that would impose mandatory
restrictions on greenhouse gas emissions. See MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE
EARNINGS POTENTIAL Environmental Matters Environmental Statutes and Regulations Air
Quality, Environmental Matters Environmental Statutes and Regulations Coal Combustion
Byproducts, and Environmental Matters Global Climate Issues of Gulf Power in Item 7 herein.
The site plan and environmental compliance plan include preliminary retirement studies under a
variety of potential scenarios for units at each of Gulf Powers coal-fired generating plants.
These studies indicate that, depending on the final requirements in these anticipated EPA
regulations and any legislation or regulations relating to greenhouse gas emissions, as well as
estimates of long-term fuel prices, Gulf Power may conclude that it is more economical to retire
certain of its coal-fired generating units prior to 2020 and to replace such units with new or
purchased capacity.
Also in December 2009, the Florida PSC adopted new numerical conservation goals for Gulf Power
along with other electric utilities in the state. The Florida PSC adopted more aggressive goals
due in part to the consideration of possible greenhouse gas emissions costs incurred in connection
with possible climate change legislation and a change in the manner in which the Florida PSC
considers the effect of so-called free-riders on the level of conservation reasonably achievable
through utility programs. Gulf Powers plans and programs to meet the new goals were submitted to
the Florida PSC for review on March 30, 2010 and were approved on January 25, 2011. The costs of
implementing Gulf Powers conservation plans and programs are recovered through specific
conservation recovery rates set annually by the Florida PSC.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
In December 2009, Mississippi Power filed its 2010 IRP with the Mississippi PSC. The filing was
made in connection with the Mississippi PSC certification proceedings relating to a new electric
generating plant located in Kemper County, Mississippi that would utilize an IGCC technology. In
the 2010 IRP, Mississippi Power projected that it will have a need for new capacity in the 2013 to
2015 timeframe. The 2010 IRP indicated a need range of approximately 200 megawatts to 300
megawatts in 2014, which reflects growth in load and the anticipated retirement of older gas steam
units Plant Eaton Units 1 through 3 and Plant Watson Units 1 through 3 in 2012 and 2013,
respectively. In addition, due to potential retirements of existing coal units, the Mississippi
PSC found a need in 2015 that ranges from 304 megawatts to 1,276 megawatts.
The range of needs for 2015 is based on potential environmental regulations relating to maximum
achievable control technology for hazardous air pollutants, as well as potential legislation or
regulations that would impose mandatory restrictions on greenhouse gas emissions. See
MANAGEMENTS DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL Environmental Matters
Environmental Statutes and Regulations Air Quality and Environmental Matters Global Climate
Issues of Mississippi Power in Item 7 herein. Depending on the final
I-14
requirements in the anticipated EPA regulations and any legislation or regulation relating to
greenhouse gas emissions, as well as estimates of long-term fuel prices, Mississippi Power may
conclude that it is more economical to discontinue burning coal at certain coal-fired generating
units than to install the required controls.
Mississippi Powers 2010 IRP indicated that Mississippi Power plans to construct the Kemper IGCC to
meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer
environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined
cycle Plant Daniel Units 3 and 4.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Base Load Construction Legislation
In the 2008 regular session of the Mississippi legislature, a bill was passed and signed by the
Governor in May 2008 to enhance the Mississippi PSCs authority to facilitate development and
construction of base load generation in the State of Mississippi (Baseload Act). The Baseload
Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism
that includes in retail base rates, prior to and during construction, all or a portion of the
prudently incurred pre-construction and construction costs incurred by a utility in constructing
a base load electric generating plant. Prior to the passage of the Baseload Act, such costs
would traditionally be recovered only after the plant was placed in service. The Baseload Act
also provides for periodic prudence reviews by the Mississippi PSC and prohibits the
cancellation of any such generating plant without the approval of the Mississippi PSC. In the
event of cancellation of the construction of the plant without approval of the Mississippi PSC,
the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to
whether and to what extent the utility will be afforded rate recovery for costs incurred in
connection with such cancelled generating plant. The effect of this legislation on Southern
Company and Mississippi Power cannot now be determined.
In January 2009, Mississippi Power filed for a CPCN with the Mississippi PSC to allow construction
of the Kemper IGCC. On April 29, 2010, the Mississippi PSC issued an order finding that
Mississippi Powers application to acquire, construct, and operate the plant did not satisfy the
requirement of public convenience and necessity in the form that the project and the related cost
recovery were originally proposed by Mississippi Power, unless Mississippi Power accepted certain
conditions on the issuance of the CPCN, including a cost cap of approximately $2.4 billion. On May
10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the
Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of
such order.
On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010
order. Among other things, the Mississippi PSCs May 26, 2010 order approved an alternate
construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions
from the cost cap; such exemptions include the costs of the lignite
mine and equipment and the carbon dioxide pipeline facilities), subject to
determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and
required by the public convenience and necessity. On May 27, 2010, Mississippi Power filed a
motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010,
the Mississippi PSC issued the final certificate order which granted Mississippi Powers motion and
issued a CPCN authorizing acquisition, construction, and operation of the plant. The Kemper IGCC,
subject to federal and state reviews and certain regulatory approvals, is expected to begin
commercial operation in May 2014. See Note 3 to the financial statements of Southern Company and
Mississippi Power in Item 8 herein for additional information.
I-15
Employee Relations
The Southern Company system had a total of 25,940 employees on its payroll at December 31,
2010.
|
|
|
|
|
|
|
Employees at December 31, 2010 |
|
Alabama Power |
|
|
6,552 |
|
Georgia Power |
|
|
8,330 |
|
Gulf Power |
|
|
1,330 |
|
Mississippi Power |
|
|
1,280 |
|
SCS |
|
|
4,465 |
|
Southern Holdings* |
|
|
|
|
Southern Nuclear |
|
|
3,676 |
|
Southern Power** |
|
|
|
|
Other |
|
|
307 |
|
|
Total |
|
|
25,940 |
|
|
|
|
|
* |
|
Southern Holdings has agreements with SCS whereby all employee services are rendered at cost. |
|
** |
|
Southern Power has no employees. Southern Power has agreements with SCS and the traditional
operating companies whereby employee services are rendered at amounts in compliance with FERC
regulations. |
The traditional operating companies have separate agreements with local unions of the IBEW
generally covering wages, working conditions, and procedures for handling grievances and
arbitration. These agreements apply with certain exceptions to operating, maintenance, and
construction employees.
Alabama Power has an agreement with the IBEW covering wages and working conditions which is in
effect through August 15, 2014.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in
effect through June 30, 2011. Upon notice given at least 60 days prior to that date, negotiations
will be initiated with respect to agreement terms to be effective after such date.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect
through September 14, 2014.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in
effect through August 15, 2014.
Southern Nuclear and the IBEW ratified a labor agreement for certain employees at Plants Hatch and
Vogtle on May 21, 2009. The agreement is effective through June 30, 2011. Upon notice given at
least 60 days prior to June 30, 2011, negotiations may be initiated with respect to a new agreement
after such date. A five-year agreement between Southern Nuclear and the IBEW representing certain
employees at Plant Farley was ratified on July 8, 2009. The agreement became effective on August
15, 2009 and will remain in effect through August 15, 2014.
Following certification of the United Government Security Officers of America (UGSOA) as the
bargaining representative for Southern Nuclear Security Officers at Plant Farley in April 2010,
negotiations continue between the UGSOA and Southern Nuclear. A
collective bargaining agreement has not yet been ratified.
The agreements also make the terms of the pension plans for the companies discussed above subject
to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon
union and company actions.
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Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, including MANAGEMENTS DISCUSSION AND
ANALYSIS FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by
Southern Company and/or its subsidiaries with the SEC from time to time, the following factors
should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors
could affect actual results and cause results to differ materially from those expressed in any
forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.
Risks Related to the Energy Industry
Southern Company and its subsidiaries are subject to substantial governmental regulation.
Compliance with current and future regulatory requirements and procurement of necessary approvals,
permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern
Power, are subject to substantial regulation from federal, state, and local regulatory agencies.
Southern Company and its subsidiaries are required to comply with numerous laws and regulations and
to obtain numerous permits, approvals, and certificates from the governmental agencies that
regulate various aspects of their businesses, including rates and charges, service regulations,
retail service territories, sales of securities, asset acquisitions and sales, accounting policies
and practices, including any changes in accounting standards, and the operation of fossil-fuel,
hydroelectric, solar, and nuclear generating facilities. For example, the rates charged to
wholesale customers by the traditional operating companies and by Southern Power must be approved
by the FERC. These wholesale rates could be affected absent the ability to conduct business
pursuant to FERC market-based rate authority. Additionally, the respective state PSCs must approve
the traditional operating companies requested rates for retail customers. While the retail rates
of the traditional operating companies are designed to provide for the full recovery of costs
(including a reasonable return on invested capital), there can be no assurance that a state PSC, in
a future rate proceeding, will not attempt to alter the timing or amount of certain costs for which
recovery is sought or to modify the current authorized rate of return.
Southern Company and its subsidiaries believe the necessary permits, approvals, and certificates
have been obtained for their respective existing operations and that their respective businesses
are conducted in accordance with applicable laws; however, the impact of any future revision or
changes in interpretations of existing regulations or the adoption of new laws and regulations
applicable to Southern Company or any of its subsidiaries cannot now be predicted. Changes in
regulation or the imposition of additional regulations could influence the operating environment of
Southern Company and its subsidiaries and may result in substantial costs.
Risks Related to Environmental and Climate Change Legislation , Regulation, and Litigation
Southern Companys, the traditional operating companies, and Southern Powers costs of compliance
with environmental laws are significant. The costs of compliance with future environmental laws,
including laws and regulations designed to address global climate change, renewable energy
standards, air and water quality, coal combustion byproducts, and other matters and the incurrence
of environmental liabilities could affect unit retirement decisions and negatively impact the net
income, cash flows, and financial condition of Southern Company, the traditional operating
companies, or Southern Power.
Southern Company, the traditional operating companies, and Southern Power are subject to extensive
federal, state, and local environmental requirements which, among other things, regulate air
emissions, water usage and discharges, and the management of hazardous and solid waste in order to
adequately protect the environment. Compliance with these legal requirements requires Southern
Company, the traditional operating companies, and Southern Power to commit significant expenditures
for installation of pollution control equipment, environmental monitoring, emissions fees, and
permits at all of their respective facilities. These expenditures are significant and Southern
Company, the traditional operating companies, and Southern Power expect that they will increase in
the future. Through 2010, Southern Company had invested approximately $8.1 billion in
environmental capital retrofit projects to comply with these requirements, with annual totals of
$500 million, $1.3 billion, and $1.6 billion for 2010, 2009, and 2008, respectively. Southern
Company expects that capital expenditures to comply with existing
I-17
statutes and regulations will be $341 million, $427 million, and $452 million for 2011, 2012, and
2013, respectively. In addition, the Southern Company system currently estimates that potential
incremental investments to comply with anticipated new environmental regulations could range from
$74 million to $289 million in 2011, $191 million to $670 million in 2012, and $476 million to $1.9
billion in 2013. The compliance strategy, including potential unit retirement and replacement
decisions, and future environmental capital expenditures will be affected by the final requirements
of any new or revised environmental statutes and regulations that are enacted, including proposed
environmental legislation and regulations, the cost, availability, and existing inventory of
emissions allowances, and the fuel mix of the electric utilities. The ultimate outcome cannot be
determined at this time.
If Southern Company, any traditional operating company, or Southern Power fails to comply with
environmental laws and regulations, even if caused by factors beyond its control, that failure may
result in the assessment of civil or criminal penalties and fines. The EPA has filed civil actions
against Alabama Power and Georgia Power and issued notices of violation to Gulf Power and
Mississippi Power alleging violations of the new source review provisions of the Clean Air Act.
Southern Company is also a party to suits alleging that emissions of carbon dioxide, a greenhouse
gas, contribute to global climate change. An adverse outcome in any of these matters could require
substantial capital expenditures that cannot be determined at this time and could possibly require
payment of substantial penalties. Such expenditures could affect unit retirement and replacement
decisions, and results of operations, cash flows, and financial condition if such costs are not
recovered through regulated rates for the traditional operating companies or market-based rates for
Southern Power.
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.
Existing environmental laws and regulations may be revised or new laws and regulations related to
global climate change, air quality, water quality, coal combustion byproducts, including coal ash,
or other environmental and health concerns may be adopted or become applicable to Southern Company,
the traditional operating companies, and Southern Power. For example, the regulation of greenhouse
gas emissions through legislation or regulation has been, and continues to be, a focus of the
current Administration. Although federal legislative proposals that would impose mandatory
requirements related to greenhouse gas emissions, renewable energy standards, and/or energy
efficiency standards failed to pass before the end of the 2010 session, such proposals are
expected to continue to be considered in the future.
While climate legislation has yet to be adopted, the EPA is moving forward with the regulation of
greenhouse gas emissions under the Clean Air Act. 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.
In December 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 April 1, 2010, the EPA issued a final rule
regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has
taken the position that when this rule became effective on January 2, 2011, carbon dioxide and
other greenhouse gases became 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 and other commercial and industrial facilities.
As a result, the construction of new facilities or the major
modifications 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.
On May 13, 2010, the
EPA issued a final rule, known as the Tailoring Rule, governing how
these programs would be applied to
stationary sources, including power plants. This rule establishes two phases for applying PSD and
Title V requirements to greenhouse gas emissions sources. The first phase, which began on January
2, 2011, applies to sources and projects that would already be covered under PSD or Title V,
whereas the second phase will begin on July 1, 2011 and applies to sources and projects that would
not otherwise trigger those programs but for their greenhouse gas emissions. In addition to these
rules, the EPA has entered into a proposed settlement agreement to issue standards of performance
for greenhouse gas emissions from new and modified fossil-fuel fired electric generating units and
greenhouse gas emissions guidelines for existing sources. Under the proposed settlement agreement,
the EPA commits to issue the proposed standards by July 2011 and the final standards by May 2012.
International climate change negotiations under the United Nations Framework Convention on Climate
Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that
included a pledge from both developed and developing countries to reduce their greenhouse gas
emissions. The most recent round of negotiations took place in
December 2010. The outcome and impact of the international
negotiations cannot be determined at this time.
I-18
Additionally, during 2010 the EPA proposed revisions, revised or issued additional regulations and
designations with respect to air quality under the Clean Air Act, including eight-hour ozone
standards, sulfur dioxide and nitrogen dioxide standards, a replacement to the Clean Air Interstate
Rule relating to nitrogen oxide and sulfur dioxide emissions, and continues to work on a proposed
Maximum Achievable Control Technology rule for coal and oil-fired electric generating units, which
will likely address numerous hazardous air pollutants, including mercury.
The EPA is currently evaluating whether additional regulation of coal combustion byproducts
(including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June
21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory
options for the management and disposal of coal combustion byproducts: regulation as a solid waste
or regulation as if the materials technically constituted a hazardous waste. Adoption of either
option could require closure of, or significant change to, existing storage facilities and
construction of lined landfills, as well as additional waste management and groundwater monitoring
requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal
combustion byproducts from regulation; however, a hazardous or other designation indicative of
heightened risk could limit or eliminate beneficial reuse options. On November 19, 2010, Southern
Company filed publicly available comments with the EPA regarding the rulemaking proposal. These
comments included a preliminary cost analysis under various alternatives in the rulemaking
proposal. Southern Company regards these estimates as pre-screening figures that should be
distinguished from the more formalized cost estimates Southern Company provides for projects that
are more definite as to the elements and timing of execution. Although its analysis was
preliminary, Southern Company concluded that potential compliance costs under the proposed rules
would be substantially higher than the estimates reflected in the
EPAs rulemaking proposal.
The ultimate cost impact of such legislation, regulation, new interpretations, or international
negotiations would depend upon the specific requirements enacted and cannot be determined at this
time. Although the outcome of such legislation, regulation, new interpretations, or international
negotiations cannot be determined at this time, legislation or regulation related to greenhouse gas
emissions, renewable energy standards, air and water quality, coal combustion byproducts and other
matters, individually or together, are likely to result in significant and additional compliance
costs, including significant capital expenditures, and could result in additional operating
restrictions. These costs will affect future unit retirement and replacement decisions, and could
result in the retirement of a significant number of coal-fired generating units of the traditional
operating companies. Moreover, the traditional operating companies could incur additional material
asset retirement obligations with respect to closing existing
coal combustion byproduct storage facilities. Additional
compliance costs and costs related to potential unit retirements could affect results of
operations, cash flows, and financial condition if such costs are not recovered from customers.
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.
Risks Related to Southern Company and its Business
The regional power market in which Southern Company and its utility subsidiaries compete may have
changing transmission regulatory structures, which could affect the ownership of these assets and
related revenues and expenses.
The traditional operating companies currently own and operate transmission facilities as part of a
vertically integrated utility. A small percentage of transmission
revenues are collected through the wholesale electric tariff but the
majority of transmission revenues are collected through retail rates.
Ongoing FERC efforts that may potentially change the regulatory
and/or operational structure of transmission could have an adverse
impact on future revenues. In addition, pending FERC regulation
pertaining to cost allocation could require the Southern Company and
its utility subsidiaries to subsidize costs outside its service
territory. The financial condition, net income, and cash flows of
Southern Company and its utility subsidiaries could be adversely
affected by pending or future changes in the federal regulatory or
operational structure of transmission.
The net income of Southern Company, the traditional operating companies, and Southern
Power could be negatively impacted by competitive activity in the wholesale electricity markets.
Competition at the wholesale level continues to evolve in the electricity markets. As a result of
changes in federal law and regulatory policy, competition in the wholesale electricity markets has
increased due to greater participation
I-19
by traditional electricity suppliers, non-utility generators, IPPs, wholesale power marketers, and
brokers. FERC rules related to transmission are designed to facilitate competition in the
wholesale market on a nationwide basis by providing greater flexibility and more choices to
wholesale power customers, including initiatives designed to promote and encourage the integration
of renewable sources of supply. Moreover, along with transactions contemplating physical delivery
of energy, futures contracts and derivatives are traded on various commodities exchanges. Southern
Company, the traditional operating companies, and Southern Power cannot predict the impact of these
and other such developments, nor can they predict the effect of changes in levels of wholesale
supply and demand, which are typically driven by factors beyond their control.
Southern Company may be unable to meet its ongoing and future financial obligations and to pay
dividends on its common stock if its subsidiaries are unable to pay upstream dividends or repay
funds to Southern Company.
Southern Company is a holding company and, as such, Southern Company has no operations of its own.
Substantially all of Southern Companys consolidated assets are held by subsidiaries. Southern
Companys ability to meet its financial obligations and to pay dividends on its common stock is
primarily dependent on the net income and cash flows of its subsidiaries and their ability to pay
upstream dividends or to repay funds to Southern Company. Prior to funding Southern Company,
Southern Companys subsidiaries have regulatory restrictions and financial obligations that must be
satisfied, including among others, debt service and preferred and preference stock dividends.
Southern Companys subsidiaries are separate legal entities and have no obligation to provide
Southern Company with funds for its payment obligations.
The financial performance of Southern Company and its subsidiaries may be adversely affected if
they are unable to
successfully operate their facilities or perform certain corporate functions.
The financial performance of Southern Company and its subsidiaries depends on the successful
operation of its subsidiaries electric generating, transmission, and distribution facilities.
Operating these facilities involves many risks, including:
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operator error or failure of equipment or processes; |
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operating limitations that may be imposed by environmental or other regulatory
requirements; |
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labor disputes; |
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terrorist attacks; |
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fuel or material supply interruptions; |
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compliance with mandatory reliability standards, including mandatory cyber security
standards; |
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information technology system failure; |
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cyber intrusion; and |
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catastrophic events such as fires, earthquakes, explosions, floods, droughts,
hurricanes, pandemic health events such as influenzas, or other similar occurrences. |
A decrease or elimination of revenues from the electric generation, transmission, or distribution
facilities or an increase in the cost of operating the facilities would reduce the net income and
cash flows and could adversely impact the financial condition of the affected traditional operating
company or Southern Power and of Southern Company.
I-20
With respect to Southern Companys investments in leverage leases, the recovery of its investment
is dependent on the profitable operation of the leased assets by the respective lessees. A
significant deterioration in the performance of the leased asset could result in the impairment of
the related lease receivable.
The
traditional operating companies and Southern Power
could be subject to higher costs and penalties as a result of
mandatory reliability standards.
As a result of the Energy Policy Act of 2005, owners and operators of bulk power transmission
systems, including the traditional operating companies, are subject to mandatory reliability
standards enacted by the North American Reliability Corporation and enforced by the FERC.
Compliance with the mandatory reliability standards may subject the
traditional operating companies, Southern Power, and Southern Company to higher operating costs and may result in increased capital expenditures.
If any traditional operating company or Southern Power is found to be in noncompliance with the mandatory reliability
standards, the traditional operating company and Southern Power could be subject to sanctions, including substantial
monetary penalties.
The revenues of Southern Company, the traditional operating companies, and Southern Power depend in
part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its
obligations, or the failure to renew the PPAs, could have a negative impact on the net income and
cash flows of the affected traditional operating company or Southern Power and of Southern Company.
Most of Southern Powers generating capacity has been sold to purchasers under PPAs. In addition,
the traditional operating companies enter into PPAs with non-affiliated parties. Revenues are
dependent on the continued performance by the purchasers of their obligations under these PPAs.
Even though Southern Power and the traditional operating companies have a rigorous credit
evaluation process, the failure of one of the purchasers to perform its obligations could have a
negative impact on the net income and cash flows of the affected traditional operating company or
Southern Power and of Southern Company. Although these credit evaluations take into account the
possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater
than the credit evaluation predicts. Additionally, neither Southern Power nor any traditional
operating company can predict whether the PPAs will be renewed at the end of their respective terms
or on what terms any renewals may be made. If a PPA is not renewed, a replacement PPA cannot be
assured.
Southern Company, the traditional operating companies, and Southern Power may incur additional
costs or delays in the construction of new plants or other facilities and may not be able to
recover their investments. The facilities of the traditional operating companies and Southern
Power require ongoing capital expenditures.
The businesses of the registrants require substantial capital expenditures for investments in new
facilities and capital improvements to transmission, distribution, and generation facilities,
including those to meet environmental standards. Certain of the traditional operating companies
and Southern Power are in the process of constructing new generating facilities and adding
environmental controls equipment at existing generating facilities. Southern Company intends to
continue its strategy of developing and constructing other new facilities, including new nuclear
generating, combined cycle, IGCC, and biomass generating units, expanding
existing facilities, and adding environmental control equipment. These types of projects are
long-term in nature and may involve facility designs that have not been finalized or previously
constructed. The completion of these types of projects without delays or significant cost overruns
is subject to substantial risks, including:
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shortages and inconsistent quality of equipment, materials, and labor; |
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work stoppages; |
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contractor or supplier non-performance under construction or other agreements; |
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delays in or failure to receive necessary permits, approvals, and other regulatory
authorizations; |
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impacts of new and existing laws and regulations, including environmental laws and
regulations;
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I-21
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continued public and policymaker support for such projects; |
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adverse weather conditions; |
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unforeseen engineering problems; |
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changes in project design or scope; |
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environmental and geological conditions; |
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delays or increased costs to interconnect facilities to transmission grids; and |
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unanticipated cost increases, including materials and labor. |
In addition, with respect to the construction of new nuclear units, a major incident at a nuclear
facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear
units. If a traditional operating company or Southern Power is unable to complete the development
or construction of a facility or decides to delay or cancel construction of a facility, it may not
be able to recover its investment in that facility and may incur substantial cancellation payments
under equipment purchase orders or construction contracts. Even if a construction project is
completed, the total costs may be higher than estimated and there is no assurance that the
traditional operating company will be able to recover such expenditures through regulated rates.
In addition, construction delays and contractor performance shortfalls can result in the loss of
revenues and may, in turn, adversely affect the net income and financial position of a traditional
operating company or Southern Power and of Southern Company.
Construction delays also may result in the loss of otherwise available investment tax credits and
other tax incentives. Furthermore, if construction projects are not completed according
to specification, a traditional operating company or Southern Power and Southern Company may incur
liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities come into commercial operation, ongoing capital expenditures are required to
maintain reliable levels of operation. Significant portions of the traditional operating
companies existing facilities were constructed many years ago. Older generation equipment, even
if maintained in accordance with good engineering practices, may require significant capital
expenditures to maintain efficiency, to comply with changing environmental requirements, or to
provide reliable operations.
Changes in technology may make Southern Companys electric generating facilities owned by the
traditional operating companies and Southern Power less competitive.
A key element of the business model of Southern Company, the traditional operating companies, and
Southern Power is that generating power at central station power plants achieves economies of scale
and produces power at a competitive cost. There are distributed generation technologies that
produce power, including fuel cells, microturbines, wind turbines, and solar cells. It is possible
that advances in technology will reduce the cost of alternative methods of producing power to a
level that is competitive with that of most central station power electric production. If this were
to happen and if these technologies achieved economies of scale, the market share of Southern
Company, the traditional operating companies, and Southern Power could be eroded, and the value of
their respective electric generating facilities could be reduced. It is also possible that rapid
advances in central station power generation technology could reduce the value of the current
electric generating facilities owned by Southern Company, the traditional operating companies, and
Southern Power. Changes in technology could also alter the channels through which electric
customers buy or utilize power, which could reduce the revenues or increase the expenses of
Southern Company, the traditional operating companies, or Southern Power.
I-22
Operation of nuclear facilities involves inherent risks, including environmental, health,
regulatory, terrorism, and financial risks, that could result in fines or the closure of Southern
Companys nuclear units owned by Alabama Power or Georgia Power and which may present potential
exposures in excess of insurance coverage.
Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds
undivided interests in, and contracts for the operation of, four existing nuclear units and the
construction of Plant Vogtle Units 3 and 4. The six existing units are operated by Southern
Nuclear and represent approximately 3,680 megawatts, or 8.6%, of Southern Companys generation
capacity as of December 31, 2010. Nuclear facilities are subject to environmental, health, and
financial risks such as on-site storage of spent nuclear fuel, the ability to dispose of such spent
nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities
arising out of the operation of these facilities, and the threat of a possible terrorist attack.
Alabama Power and Georgia Power maintain decommissioning trusts and external insurance coverage to
minimize the financial exposure to these risks; however, it is possible that damages could exceed
the amount of insurance coverage.
The NRC has broad authority under federal law to impose licensing and safety-related requirements
for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has
the authority to impose fines or shut down any unit, depending upon its assessment of the severity
of the situation, until compliance is achieved. NRC orders or regulations related to increased
security measures and any future safety requirements promulgated by the NRC could require Alabama
Power and Georgia Power to make substantial operating and capital expenditures at their nuclear
plants. In addition, although Alabama Power, Georgia Power, and Southern Company have no reason to
anticipate a serious nuclear incident at their plants, if an incident did occur, it could result in
substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a
nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or
licensing of any domestic nuclear unit.
In addition, potential terrorist threats and increased public scrutiny of utilities could result in
increased nuclear licensing or compliance costs that are difficult or impossible to predict.
The generation operations and energy marketing operations of Southern Company, the traditional
operating companies, and Southern Power are subject to risks, many of which are beyond their
control, including changes in power prices and fuel costs, that may reduce Southern Companys, the
traditional operating companies, and Southern Powers revenues and increase costs.
The generation operations and energy marketing operations of Southern Company, the traditional
operating companies, and Southern Power are subject to changes in power prices or fuel costs, which
could increase the cost of producing power or decrease the amount Southern Company, the traditional
operating companies, and Southern Power receive from the sale of power. The market prices for
these commodities may fluctuate significantly over relatively short periods of time. In addition,
the proportion of natural gas generation to the total fuel mix is likely to increase in the future.
Southern Company, the traditional operating companies, and Southern Power attempt to mitigate
risks associated with fluctuating fuel costs by passing these costs on to customers through the
traditional operating companies fuel cost recovery clauses or through PPAs. Among the factors
that could influence power prices and fuel costs are:
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prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and
other fuels used in the generation facilities of the traditional operating companies
and Southern Power including associated transportation costs, and supplies of such
commodities; |
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demand for energy and the extent of additional supplies of energy available
from current or new competitors; |
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liquidity in the general wholesale electricity market; |
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weather conditions impacting demand for electricity; |
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seasonality; |
I-23
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transmission or transportation constraints or inefficiencies; |
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availability of competitively priced alternative energy sources; |
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forced or unscheduled plant outages for the Southern Company system, its
competitors, or third party providers; |
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the financial condition of market participants; |
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the economy in the service territory, the nation, and worldwide, including the
impact of economic conditions on industrial and commercial demand for electricity and
the worldwide demand for fuels; |
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natural disasters, wars, embargos, acts of terrorism, and other catastrophic
events; and |
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federal, state, and foreign energy and environmental regulation and
legislation. |
Certain of these factors could increase the expenses of the traditional operating companies or
Southern Power and Southern Company. For the traditional operating companies, such increases may
not be fully recoverable through rates. Other of these factors could reduce the revenues of the
traditional operating companies or Southern Power and Southern Company.
Historically, the traditional operating companies from time to time have experienced underrecovered
fuel cost balances and deficits in their storm cost recovery reserve balances and may experience
such balances in the future. While the traditional operating companies are generally authorized to
recover underrecovered fuel costs through fuel cost recovery clauses and storm recovery costs
through special rate provisions administered by the respective PSCs, recovery may be denied if
costs are deemed to be imprudently incurred and delays in the authorization of such recovery could
negatively impact the cash flows of the affected traditional operating company and Southern
Company.
A downgrade in the credit ratings of Southern Company, the traditional operating companies, or
Southern Power could negatively affect their ability to access capital at reasonable costs and/or
could require Southern Company, the traditional operating companies, or Southern Power to post
collateral or replace certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for
Southern Company, the traditional operating companies, and Southern Power, including capital
structure, regulatory environment, the ability to cover liquidity requirements, and other
commitments for capital. Southern Company, the traditional operating companies, and Southern Power
could experience a downgrade in their ratings if any of the rating agencies conclude that the level
of business or financial risk of the industry or Southern Company, the traditional operating
companies, or Southern Power has deteriorated. Changes in ratings methodologies by the agencies
could also have a negative impact on credit ratings. If one or more rating agencies downgrade
Southern Company, the traditional operating companies, or Southern Power, borrowing costs would
increase, its pool of investors and funding sources would likely decrease, and, particularly for
any downgrade to below investment grade, significant collateral requirements may be triggered in a
number of contracts.
The use of derivative contracts by Southern Company and its subsidiaries in the normal course of
business could result in financial losses that negatively impact the net income of Southern Company
and its subsidiaries.
Southern Company and its subsidiaries, including the traditional operating companies and Southern
Power, use derivative instruments, such as swaps, options, futures, and forwards, to manage their
commodity and interest rate exposures and, to a lesser extent, engage in limited trading
activities. Southern Company and its subsidiaries could recognize financial losses as a result of
volatility in the market values of these contracts or if a counterparty fails to perform. These
risks are managed through risk management policies, limits, and procedures. These risk
I-24
management policies, limits, and procedures might not work as planned and cannot entirely eliminate
the risks associated with these activities. In addition, derivative contracts entered for hedging
purposes might not off-set the underlying exposure being hedged as expected resulting in financial
losses. In the absence of actively quoted market prices and pricing information from external
sources, the valuation of these financial instruments can involve managements judgment or use of
estimates. The factors used in the valuation of these instruments become more difficult to predict
and the calculations become less reliable the further into the future these estimates are made. As
a result, changes in the underlying assumptions or use of alternative valuation methods could
affect the value of the reported fair value of these contracts.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010
could impact the use of over-the-counter derivatives by Southern Company and its subsidiaries.
Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of
over-the-counter derivatives, such as margin and reporting requirements, which could affect both
the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until
regulations are finalized.
The traditional operating companies and Southern Power may not be able to obtain adequate fuel
supplies, which could limit their ability to operate their facilities.
The traditional operating companies and Southern Power purchase fuel, including coal, natural gas,
uranium, fuel oil, and biomass, from a number of suppliers. Disruption in the delivery of fuel,
including disruptions as a result of, among other things, transportation delays, weather, labor
relations, force majeure events, or environmental regulations affecting any of these fuel
suppliers, could limit the ability of the traditional operating companies and Southern Power to
operate their respective facilities, and thus reduce the net income of the affected traditional
operating company or Southern Power and Southern Company.
The traditional operating companies are dependent on coal for much of their electric generating
capacity. Each traditional operating company has coal supply contracts in place; however, there
can be no assurance that the counterparties to these agreements will fulfill their obligations to
supply coal to the traditional operating companies. The suppliers under these agreements may
experience financial or technical problems which inhibit their ability to fulfill their obligations
to the traditional operating companies. In addition, the suppliers under these agreements may not
be required to supply coal to the traditional operating companies under certain circumstances, such
as in the event of a natural disaster. If the traditional operating companies are unable to obtain
their coal requirements under these contracts, the traditional operating companies may be required
to purchase their coal requirements at higher prices, which may not be fully recoverable through
rates.
In addition, the traditional operating companies and Southern Power to a greater extent are
dependent on natural gas for a portion of their electric generating capacity. Natural gas supplies
can be subject to disruption in the event production or distribution is curtailed, such as in the
event of a hurricane.
In addition, world market conditions for fuels can impact the availability of natural gas, coal,
and uranium.
Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity
in the open market or building additional generation capabilities.
Through the traditional operating companies and Southern Power, Southern Company is currently
obligated to supply power to retail customers and wholesale customers under long-term PPAs. At
peak times, the demand for power required to meet this obligation could exceed Southern Companys
available generation capacity. Market or competitive forces may require that the traditional
operating companies or Southern Power purchase capacity on the open market or build additional
generation capabilities. Because regulators may not permit the traditional operating companies to
pass all of these purchase or construction costs on to their customers, the traditional operating
companies may not be able to recover any of these costs or may have exposure to regulatory lag
associated with the time between the incurrence of costs of purchased or constructed capacity and
the traditional operating companies recovery in customers rates. Under Southern Powers
long-term fixed price PPAs, Southern Power would not have the ability to recover any of these
costs. These situations could have negative impacts on net income and cash flows for the affected
traditional operating company or Southern Power and Southern Company.
I-25
Demand for power could decrease or fail to grow at expected rates, resulting in stagnant or reduced
revenues, limited growth opportunities, and potentially stranded generation assets.
Southern Company, the traditional operating companies, and Southern Power each engage in a
long-term planning process to determine the optimal mix and timing of new generation assets
required to serve future load obligations. This planning process must look many years into the
future in order to accommodate the long lead times associated with the permitting and construction
of new generation facilities. Inherent risk exists in predicting demand this far into the future
as these future loads are dependent on many uncertain factors, including regional economic
conditions, customer usage patterns, efficiency programs, and customer technology adoption.
Because regulators may not permit the traditional operating companies to adjust rates to recover
the costs of new generation assets while such assets are being constructed, the traditional
operating companies may not be able to fully recover these costs or may have exposure to regulatory
lag associated with the time between the incurrence of costs of additional capacity and the
traditional operating companies recovery in customers rates. Under Southern Powers model of
selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power
might not be able to fully execute its business plan if market prices drop below original
forecasts. Southern Power may not be able to extend its existing PPAs or to find new buyers for
existing generation assets as existing PPAs expire, or it may be forced to market these assets at
prices lower than originally intended. These situations could have negative impacts on net income
and cash flows for the affected traditional operating company or Southern Power and Southern
Company.
The operating results of Southern Company, the traditional operating companies, and Southern Power
are affected by weather conditions and may fluctuate on a seasonal and quarterly basis. In
addition, significant weather events, such as hurricanes, tornadoes, floods, and droughts, or a
terrorist attack could result in substantial damage to or limit the operation of the properties of
the traditional operating companies and Southern Power and could negatively impact results of
operation, financial condition, and liquidity.
Electric power supply is generally a seasonal business. In many parts of the country, demand for
power peaks during the summer months, with market prices also peaking at that time. In other
areas, power demand peaks during the winter. As a result, the overall operating results of
Southern Company, the traditional operating companies, and Southern Power in the future may
fluctuate substantially on a seasonal basis. In addition, the traditional operating companies and
Southern Power have historically sold less power when weather conditions are milder. Unusually
mild weather in the future could reduce the revenues, net income, available cash, and borrowing
ability of Southern Company, the traditional operating companies, and Southern Power.
In addition, volatile or significant weather events or a terrorist attack could result in
substantial damage to the transmission and distribution lines of the traditional operating
companies and the generating facilities of the traditional operating companies and Southern Power.
The traditional operating companies and Southern Power have significant investments in the Atlantic
and Gulf Coast regions which could be subject to major storm activity. Further, severe drought
conditions can reduce the availability of water and restrict or prevent the operation of certain
generating facilities.
Each traditional operating company maintains a reserve for property damage to cover the cost of
damages from weather events to its transmission and distribution lines and the cost of uninsured
damages to its generating facilities and other property. In the event a traditional operating
company experiences any of these weather events or any natural disaster, or other catastrophic
event, such as a terrorist attack, recovery of costs in excess of reserves and insurance coverage
is subject to the approval of its state PSC. While the traditional operating companies generally
are entitled to recover prudently incurred costs incurred in connection with such an event, any
denial by the applicable state PSC or delay in recovery of any portion of such costs could have a
material negative impact on a traditional operating companys and Southern Companys results of
operations, financial condition, and liquidity.
In addition, damages resulting from significant weather events within the service territory of any
traditional operating company or affecting Southern Powers customers may result in the loss of
customers and reduced demand for electricity for extended periods. For example, Hurricane Katrina
hit the Gulf Coast of Mississippi in August 2005 and caused substantial damage within Mississippi
Powers service territory. As of December 31, 2010, Mississippi Power had approximately 4.3% fewer
retail customers as compared to pre-storm levels. Any significant
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loss of customers or reduction in demand for electricity could have a material negative impact on a
traditional operating companys, Southern Powers, and Southern Companys results of operations,
financial condition, and liquidity.
Failure to attract and retain an appropriately qualified workforce could negatively impact Southern
Companys and its subsidiaries results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skillset to future
needs, or unavailability of contract resources may lead to operating challenges or increased costs.
Such operating challenges include lack of resources, loss of knowledge, and a lengthy time period
associated with skill development, especially with the workforce needs associated with new nuclear
construction. Failure to hire and adequately obtain replacement employees, including the ability
to transfer significant internal historical knowledge and expertise to the new employees, or the
future availability and cost of contract labor may adversely affect Southern Company and its
subsidiaries ability to manage and operate their businesses. If Southern Company and its
subsidiaries, including the traditional operating companies, are unable to successfully attract and
retain an appropriately qualified workforce, results of operations could be negatively impacted.
Risks Related to Market and Economic Volatility
The business of Southern Company, the traditional operating companies, and Southern Power is
dependent on their ability to successfully access funds through capital markets and financial
institutions. The inability of Southern Company, any traditional operating company, or Southern
Power to access funds may limit its ability to execute its business plan by impacting its ability
to fund capital investments or acquisitions that Southern Company, the traditional operating
companies, or Southern Power may otherwise rely on to achieve future earnings and cash flows.
Southern Company, the traditional operating companies, and Southern Power rely on access to both
short-term money markets and longer-term capital markets as a significant source of liquidity for
capital requirements not satisfied by the cash flow from their respective operations. If Southern
Company, any traditional operating company, or Southern Power is not able to access capital at
competitive rates, its ability to implement its business plan will be limited by impacting its
ability to fund capital investments or acquisitions that Southern Company, the traditional
operating companies, or Southern Power may otherwise rely on to achieve future earnings and cash
flows. In addition, Southern Company, the traditional operating companies, and Southern Power rely
on committed bank lending agreements as back-up liquidity which allows them to access low cost
money markets. Each of Southern Company, the traditional operating companies, and Southern Power
believes that it will maintain sufficient access to these financial markets based upon current
credit ratings. However, certain market disruptions may increase its cost of borrowing or
adversely affect its ability to raise capital through the issuance of securities or other borrowing
arrangements or its ability to secure committed bank lending agreements used as back-up sources of
capital. Such disruptions could include:
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an economic downturn or uncertainty; |
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the bankruptcy or financial distress at an unrelated energy company or financial
institution; |
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capital markets volatility and interruption; |
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market prices for electricity and gas; |
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terrorist attacks or threatened attacks on Southern Companys facilities or
unrelated energy companies facilities; |
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war or threat of war; or |
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the overall health of the utility and financial institution industries. |
I-27
Market performance and other changes may decrease the value of benefit plans and nuclear
decommissioning trust assets or may increase plan costs, which then could require significant
additional funding.
The performance of the capital markets affects the values of the assets held in trust under
Southern Companys pension and postretirement benefit plans and the assets held in trust to satisfy
obligations to decommission Alabama Powers and Georgia Powers nuclear plants. Southern Company,
Alabama Power, and Georgia Power have significant obligations in these areas and hold significant
assets in these trusts. These assets are subject to market fluctuations and will yield uncertain
returns, which may fall below projected return rates. A decline in the market value of these
assets, as has been experienced in prior periods, may increase the funding requirements relating to
Southern Companys benefit plan liabilities and Alabama Powers and Georgia Powers nuclear
decommissioning obligations. Additionally, changes in interest rates affect the liabilities under
Southern Companys pension and postretirement benefit plans; as interest rates decrease, the
liabilities increase, potentially requiring additional funding. Further, changes in demographics,
including increased numbers of retirements or changes in life expectancy assumptions, may also
increase the funding requirements of the obligations related to the pension benefit plans.
Southern Company and its subsidiaries are also facing rising medical benefit costs, including the
current costs for active and retired employees. It is possible that these costs may increase at a
rate that is significantly higher than anticipated. If Southern Company is unable to successfully
manage benefit plan assets and medical benefit costs and Alabama Power and Georgia Power are unable
to successfully manage the nuclear decommissioning trust funds, results of operations and financial
position could be negatively affected. Additionally, Southern Company and its subsidiaries may
also be affected by healthcare legislation.
Southern Company, the traditional operating companies, and Southern Power are subject to risks
associated with a changing economic environment, which could impact their ability to obtain
adequate insurance and the financial stability of the customers of the traditional operating
companies and Southern Power.
The financial condition of some insurance companies, the threat of terrorism, and the hurricanes
that affected the Gulf Coast, among other things, have had disruptive effects on the insurance
industry. The availability of insurance covering risks that Southern Company, the traditional
operating companies, Southern Power, and their respective competitors typically insure against may
decrease, and the insurance that Southern Company, the traditional operating companies, and
Southern Power are able to obtain may have higher deductibles, higher premiums, and more
restrictive policy terms.
Additionally, Southern Company, the traditional operating companies, and Southern Power are exposed
to risks related to general economic conditions in their applicable service territory and are thus
impacted by the economic cycles of the customers each serves. Any economic downturn or disruption
of financial markets could negatively affect the financial stability of the customers and
counterparties of the traditional operating companies and Southern Power. As territories served by
the traditional operating companies and Southern Power experience economic downturns, energy
consumption patterns may change and revenues may be negatively impacted. Additionally, customers
could voluntarily reduce their consumption of electricity in response to decreases in their
disposable income or individual conservation efforts. If commercial and industrial customers
experience economic downturns, their consumption of electricity may decline. As a result, revenues
may be negatively impacted.
Further, the results of operations of the traditional operating companies and Southern Power are
affected by customer growth in their applicable service territory. Customer growth and customer
usage can be affected by economic factors in the service territory of the traditional operating
companies and Southern Power and elsewhere, including, for example, job and income growth, housing
starts, and new home prices. A population decline and/or business closings in the territory served
by the traditional operating companies or Southern Power or slower than anticipated customer growth
as a result of the recent recession or otherwise could also have a negative impact on revenues and
could result in greater expense for uncollectible customer balances.
As with other parts of the country, the territories served by the traditional operating companies
and Southern Power have been impacted by the recent economic recession. The traditional operating
companies have experienced some decline in the rate of residential and commercial sales growth, and
also have experienced declining sales to commercial and industrial customers due to the recent
economic recession. Southern Power is expected to continue to experience reduced future revenues
for its requirements customers due to the recent economic recession. The
timing and extent of the recovery cannot be predicted.
I-28
These and the other factors discussed above could adversely affect Southern Companys, the
traditional operating companies, and Southern Powers level of future net income.
Energy conservation and energy price increases could negatively impact financial results.
A number of regulatory and legislative bodies have proposed or introduced requirements
and/or incentives to reduce energy consumption by certain dates. Conservation programs
could impact the financial results of Southern Company, the traditional operating
companies, and Southern Power in different ways. To the extent conservation results in
reduced energy demand or significantly slows the growth in demand, the value of wholesale
generation assets of the traditional operating companies and Southern Power and other
unregulated business activities could be adversely impacted. In addition, conservation
could negatively impact the traditional operating companies depending on the regulatory
treatment of the associated impacts. If any traditional operating company is required to
invest in conservation measures that result in reduced sales from effective conservation,
regulatory lag in adjusting rates for the impact of these measures could have a negative
financial impact on such traditional operating company and Southern Company. Southern
Company, the traditional operating companies, and Southern Power could also be impacted if
any future energy price increases result in a decrease in customer usage. Southern
Company, the traditional operating companies, and Southern Power are unable to determine
what impact, if any, conservation and increases in energy prices will have on financial
condition or results of operations.
Item 1B. UNRESOLVED STAFF COMMENTS.
None.
I-29
Item 2. PROPERTIES
Electric Properties
The traditional operating companies, Southern Power, Southern Renewable Energy, and SEGCO, at
December 31, 2010, owned and/or operated 33 hydroelectric generating stations, 34 fossil fuel
generating stations, three nuclear generating stations, and 12 combined cycle/cogeneration
stations, one solar facility, and one landfill gas facility. The amounts of capacity for each
company are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
Nameplate |
Generating Station |
|
Location |
|
Capacity (1) |
|
|
|
|
|
(Kilowatts) |
|
FOSSIL STEAM |
|
|
|
|
|
|
Gadsden |
|
Gadsden, AL |
|
|
120,000 |
|
Gorgas |
|
Jasper, AL |
|
|
1,221,250 |
|
Barry |
|
Mobile, AL |
|
|
1,525,000 |
|
Greene County |
|
Demopolis, AL |
|
|
300,000 |
(2) |
Gaston Unit 5 |
|
Wilsonville, AL |
|
|
880,000 |
|
Miller |
|
Birmingham, AL |
|
|
2,532,288 |
(3) |
|
|
|
|
|
|
|
Alabama Power Total |
|
|
|
|
6,578,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bowen |
|
Cartersville, GA |
|
|
3,160,000 |
|
Branch |
|
Milledgeville, GA |
|
|
1,539,700 |
|
Hammond |
|
Rome, GA |
|
|
800,000 |
|
Kraft |
|
Port Wentworth, GA |
|
|
281,136 |
|
McDonough (4) |
|
Atlanta, GA |
|
|
490,000 |
|
McIntosh |
|
Effingham County, GA |
|
|
163,117 |
|
McManus |
|
Brunswick, GA |
|
|
115,000 |
|
Mitchell |
|
Albany, GA |
|
|
125,000 |
|
Scherer |
|
Macon, GA |
|
|
750,924 |
(5) |
Wansley |
|
Carrollton, GA |
|
|
925,550 |
(6) |
Yates |
|
Newnan, GA |
|
|
1,250,000 |
|
|
|
|
|
|
|
|
Georgia Power Total |
|
|
|
|
9,600,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crist |
|
Pensacola, FL |
|
|
970,000 |
|
Daniel |
|
Pascagoula, MS |
|
|
500,000 |
(7) |
Lansing Smith |
|
Panama City, FL |
|
|
305,000 |
|
Scholz |
|
Chattahoochee, FL |
|
|
80,000 |
|
Scherer Unit 3 |
|
Macon, GA |
|
|
204,500 |
(5) |
|
|
|
|
|
|
|
Gulf Power Total |
|
|
|
|
2,059,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daniel |
|
Pascagoula, MS |
|
|
500,000 |
(7) |
Eaton |
|
Hattiesburg, MS |
|
|
67,500 |
|
Greene County |
|
Demopolis, AL |
|
|
200,000 |
(2) |
Sweatt |
|
Meridian, MS |
|
|
80,000 |
|
Watson |
|
Gulfport, MS |
|
|
1,012,000 |
|
|
|
|
|
|
|
|
Mississippi Power Total |
|
|
|
|
1,859,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gaston Units 1-4 |
|
Wilsonville, AL |
|
|
|
|
SEGCO Total |
|
|
|
|
1,000,000 |
(8) |
|
|
|
|
|
|
|
Total Fossil Steam |
|
|
|
|
21,097,965 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NUCLEAR STEAM |
|
|
|
|
|
|
Farley |
|
Dothan, AL |
|
|
|
|
Alabama Power Total |
|
|
|
|
1,720,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hatch |
|
Baxley, GA |
|
|
899,612 |
(9) |
Vogtle |
|
Augusta, GA |
|
|
1,060,240 |
(10) |
|
|
|
|
|
|
|
Georgia Power Total |
|
|
|
|
1,959,852 |
|
|
|
|
|
|
|
|
Total Nuclear Steam |
|
|
|
|
3,679,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMBUSTION TURBINES |
|
|
|
|
|
|
Greene County |
|
Demopolis, AL |
|
|
|
|
Alabama Power Total |
|
|
|
|
720,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Boulevard |
|
Savannah, GA |
|
|
59,100 |
|
Bowen |
|
Cartersville, GA |
|
|
39,400 |
|
Intercession City |
|
Intercession City, FL |
|
|
47,667 |
(11) |
Kraft |
|
Port Wentworth, GA |
|
|
22,000 |
|
McDonough |
|
Atlanta, GA |
|
|
78,800 |
|
McIntosh Units 1
through 8 |
|
Effingham County, GA |
|
|
640,000 |
|
McManus |
|
Brunswick, GA |
|
|
481,700 |
|
Mitchell |
|
Albany, GA |
|
|
118,200 |
|
Robins |
|
Warner Robins, GA |
|
|
158,400 |
|
Wansley |
|
Carrollton, GA |
|
|
26,322 |
(6) |
Wilson |
|
Augusta, GA |
|
|
354,100 |
|
|
|
|
|
|
|
|
Georgia Power Total |
|
|
|
|
2,025,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lansing Smith Unit A |
|
Panama City, FL |
|
|
39,400 |
|
Pea Ridge Units 1-3 |
|
Pea Ridge, FL |
|
|
15,000 |
|
|
|
|
|
|
|
|
Gulf Power Total |
|
|
|
|
54,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron Cogenerating
Station |
|
Pascagoula, MS |
|
|
147,292 |
(12) |
Sweatt |
|
Meridian, MS |
|
|
39,400 |
|
I-30
|
|
|
|
|
|
|
|
|
|
|
Nameplate |
Generating Station |
|
Location |
|
Capacity (1) |
|
|
|
|
|
(Kilowatts) |
|
Watson |
|
Gulfport, MS |
|
|
39,360 |
|
|
|
|
|
|
|
|
Mississippi Power Total |
|
|
|
|
226,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dahlberg |
|
Jackson County, GA |
|
|
756,000 |
|
Oleander |
|
Cocoa, FL |
|
|
791,301 |
|
Rowan |
|
Salisbury, NC |
|
|
455,250 |
|
West Georgia |
|
Thomaston, GA |
|
|
668,800 |
|
|
|
|
|
|
|
|
Southern Power Total |
|
|
|
|
2,671,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gaston (SEGCO) |
|
Wilsonville, AL |
|
|
19,680 |
(8) |
|
|
|
|
|
|
|
Total Combustion Turbines |
|
|
|
|
5,717,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COGENERATION |
|
|
|
|
|
|
Washington County |
|
Washington County, AL |
|
|
123,428 |
|
GE Plastics Project |
|
Burkeville, AL |
|
|
104,800 |
|
Theodore |
|
Theodore, AL |
|
|
236,418 |
|
|
|
|
|
|
|
|
Total Cogeneration |
|
|
|
|
464,646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMBINED CYCLE |
|
|
|
|
|
|
Barry |
|
Mobile, AL |
|
|
|
|
Alabama Power Total |
|
|
|
|
1,070,424 |
|
|
|
|
|
|
|
|
McIntosh Units 10&11 |
|
Effingham County, GA |
|
|
|
|
Georgia Power Total |
|
|
|
|
1,318,920 |
|
|
|
|
|
|
|
|
Smith |
|
Lynn Haven, FL |
|
|
|
|
Gulf Power Total |
|
|
|
|
545,500 |
|
|
|
|
|
|
|
|
Daniel (Leased) |
|
Pascagoula, MS |
|
|
|
|
Mississippi Power Total |
|
|
|
|
1,070,424 |
|
|
|
|
|
|
|
|
Franklin |
|
Smiths, AL |
|
|
1,857,820 |
|
Harris |
|
Autaugaville, AL |
|
|
1,318,920 |
|
Rowan |
|
Salisbury, NC |
|
|
530,550 |
|
Stanton Unit A |
|
Orlando, FL |
|
|
428,649 |
(13) |
Wansley |
|
Carrollton, GA |
|
|
1,073,000 |
|
|
|
|
|
|
|
|
Southern Power Total |
|
|
|
|
5,208,939 |
|
|
|
|
|
|
|
|
Total Combined Cycle |
|
|
|
|
9,214,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HYDROELECTRIC FACILITIES |
|
|
|
|
|
|
Bankhead |
|
Holt, AL |
|
|
53,985 |
|
Bouldin |
|
Wetumpka, AL |
|
|
225,000 |
|
Harris |
|
Wedowee, AL |
|
|
132,000 |
|
Henry |
|
Ohatchee, AL |
|
|
72,900 |
|
Holt |
|
Holt, AL |
|
|
46,944 |
|
Jordan |
|
Wetumpka, AL |
|
|
100,000 |
|
Lay |
|
Clanton, AL |
|
|
177,000 |
|
Lewis Smith |
|
Jasper, AL |
|
|
157,500 |
|
Logan Martin |
|
Vincent, AL |
|
|
135,000 |
|
Martin |
|
Dadeville, AL |
|
|
182,000 |
|
Mitchell |
|
Verbena, AL |
|
|
170,000 |
|
Thurlow |
|
Tallassee, AL |
|
|
81,000 |
|
Weiss |
|
Leesburg, AL |
|
|
87,750 |
|
Yates |
|
Tallassee, AL |
|
|
47,000 |
|
|
|
|
|
|
|
|
Alabama Power Total |
|
|
|
|
1,668,079 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bartletts Ferry |
|
Columbus, GA |
|
|
173,000 |
|
Goat Rock |
|
Columbus, GA |
|
|
38,600 |
|
Lloyd Shoals |
|
Jackson, GA |
|
|
14,400 |
|
Morgan Falls |
|
Atlanta, GA |
|
|
16,800 |
|
North Highlands |
|
Columbus, GA |
|
|
29,600 |
|
Oliver Dam |
|
Columbus, GA |
|
|
60,000 |
|
Rocky Mountain |
|
Rome, GA |
|
|
215,256 |
(14) |
Sinclair Dam |
|
Milledgeville, GA |
|
|
45,000 |
|
Tallulah Falls |
|
Clayton, GA |
|
|
72,000 |
|
Terrora |
|
Clayton, GA |
|
|
16,000 |
|
Tugalo |
|
Clayton, GA |
|
|
45,000 |
|
Wallace Dam |
|
Eatonton, GA |
|
|
321,300 |
|
Yonah |
|
Toccoa, GA |
|
|
22,500 |
|
6 Other Plants |
|
|
|
|
18,080 |
|
|
|
|
|
|
|
|
Georgia Power Total |
|
|
|
|
1,087,536 |
|
|
|
|
|
|
|
|
Total Hydroelectric Facilities |
|
|
|
|
2,755,615 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SOLAR |
|
|
|
|
|
|
Cimarron |
|
Springer, NM |
|
|
|
|
Southern Renewable Total |
|
|
|
|
30,000 |
(15) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LANDFILL GAS |
|
|
|
|
|
|
Perdido |
|
Escambia County, FL |
|
|
|
|
Gulf Power Total |
|
|
|
|
3,200 |
|
|
|
|
|
|
|
|
|
Total Generating Capacity |
|
|
|
|
42,962,657 |
|
|
|
|
|
|
|
|
|
|
|
Notes: |
|
(1) |
|
See Jointly-Owned Facilities herein for additional information. |
|
(2) |
|
Owned by Alabama Power and Mississippi Power as tenants in common in
the proportions of 60% and 40%, respectively. |
|
(3) |
|
Capacity shown is Alabama Powers portion (91.84%) of total plant
capacity. |
I-31
|
|
|
(4) |
|
McDonough Units 1 and 2 are scheduled to be retired in April 2012 and
October 2011, respectively. |
|
(5) |
|
Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of
Unit 3. Capacity shown for Gulf Power is 25% of Unit 3. |
|
(6) |
|
Capacity shown is Georgia Powers portion (53.5%) of total plant
capacity. |
|
(7) |
|
Represents 50% of the plant which is owned as tenants in common by
Gulf Power and Mississippi Power. |
|
(8) |
|
SEGCO is jointly-owned by Alabama Power and Georgia Power. See
BUSINESS in Item 1 herein for additional information. |
|
(9) |
|
Capacity shown is Georgia Powers portion (50.1%) of total plant
capacity. |
|
(10) |
|
Capacity shown is Georgia Powers portion (45.7%) of total plant
capacity. |
|
(11) |
|
Capacity shown represents 33 1/3% of total plant capacity. Georgia
Power owns a 1/3 interest in the unit with 100% use of the unit from
June through September. Progress Energy Florida operates the unit. |
|
(12) |
|
Generation is dedicated to a single industrial customer. |
|
(13) |
|
Capacity shown is Southern Powers portion (65%) of total plant
capacity. |
|
(14) |
|
Capacity shown is Georgia Powers portion (25.4%) of total plant
capacity. OPC operates the plant. |
|
(15) |
|
The Cimarron solar facility is owned by an indirect subsidiary of
Southern Renewable Energy.
The kilowatts shown represents 100% of the facilitys capacity. |
Except as discussed below under Titles to Property, the principal plants and other important
units of the traditional operating companies, Southern Power, and SEGCO are owned in fee by the
respective companies. It is the opinion of management of each such company that its operating
properties are adequately maintained and are substantially in good operating condition.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to
Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state
line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the
amortization of the original $57 million cost of the line. At December 31, 2010, the unamortized
portion of this cost was approximately $20.6 million.
In 2010, the maximum demand on the traditional operating companies, Southern Power, and SEGCO was
36,321,000 kilowatts and occurred on July 26, 2010. The all-time maximum demand of 38,777,000
kilowatts on the traditional operating companies, Southern Power, and SEGCO occurred on August 22,
2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The
reserve margin for the traditional operating companies, Southern Power, and SEGCO in 2010 was 23%.
See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands for each
registrant.
I-32
Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power have undivided interests in certain generating
plants and other related facilities to or from non-affiliated parties. The percentages of
ownership are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage Ownership |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Progress |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Alabama |
|
|
Power |
|
|
Georgia |
|
|
|
|
|
|
MEAG |
|
|
|
|
|
|
Energy |
|
|
Southern |
|
|
|
|
|
|
|
|
|
|
|
|
Capacity |
|
|
Power |
|
|
South |
|
|
Power |
|
|
OPC |
|
|
Power |
|
|
Dalton |
|
|
Florida |
|
|
Power |
|
|
OUC |
|
|
FMPA |
|
|
KUA |
|
|
|
(Megawatts) |
|
Plant Miller
Units 1 and 2 |
|
|
1,320 |
|
|
|
91.8 |
% |
|
|
8.2 |
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
Plant Hatch |
|
|
1,796 |
|
|
|
|
|
|
|
|
|
|
|
50.1 |
|
|
|
30.0 |
|
|
|
17.7 |
|
|
|
2.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Vogtle |
|
|
2,320 |
|
|
|
|
|
|
|
|
|
|
|
45.7 |
|
|
|
30.0 |
|
|
|
22.7 |
|
|
|
1.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Scherer
Units 1 and 2 |
|
|
1,636 |
|
|
|
|
|
|
|
|
|
|
|
8.4 |
|
|
|
60.0 |
|
|
|
30.2 |
|
|
|
1.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Wansley |
|
|
1,779 |
|
|
|
|
|
|
|
|
|
|
|
53.5 |
|
|
|
30.0 |
|
|
|
15.1 |
|
|
|
1.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain |
|
|
848 |
|
|
|
|
|
|
|
|
|
|
|
25.4 |
|
|
|
74.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercession City, FL |
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
33.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Stanton A |
|
|
660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65 |
% |
|
|
28 |
% |
|
|
3.5 |
% |
|
|
3.5 |
% |
|
Alabama Power and Georgia Power have contracted to operate and maintain the respective units
in which each has an interest (other than Rocky Mountain and Intercession City) as agent for the
joint owners. SCS provides operation and maintenance services for Plant Stanton A.
In addition, Georgia Power has commitments regarding a portion of a five percent interest in Plant
Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the
plant or the latest stated maturity date of MEAG Powers bonds issued to finance such ownership
interest. The payments for capacity are required whether any capacity is available. The energy
cost is a function of each units variable operating costs. Except for the portion of the capacity
payments related to the Georgia PSCs disallowances of Plant Vogtle Units 1 and 2 costs, the cost
of such capacity and energy is included in purchased power from non-affiliates in Georgia Powers
statements of income in Item 8 herein. Also see Note 7 to the financial statements of Georgia Power
under Commitments Purchased Power Commitments in Item 8 herein for additional information.
Titles to Property
The traditional operating companies, Southern Powers, and SEGCOs interests in the principal
plants (other than certain pollution control facilities, combined cycle units at Plant Daniel
leased by Mississippi Power, and the land on which five combustion turbine generators of
Mississippi Power are located, which is held by easement) and other important units of the
respective companies are owned in fee by such companies, subject only to the liens pursuant to
pollution control revenue bonds of Alabama Power and Gulf Power on specific pollution control
facilities. See Note 6 to the financial statements of Southern Company, Alabama Power, and Gulf
Power under Assets Subject to Lien and Note 7 to the financial statements of Mississippi Power
under Operating Leases Plant Daniel Combined Cycle Generating Units in Item 8 herein for
additional information. The traditional operating companies own the fee interests in certain of
their principal plants as tenants in common. See Jointly-Owned Facilities herein for additional
information. Properties such as electric transmission and distribution lines and steam heating
mains are constructed principally on rights-of-way which are maintained under franchise or are held
by easement only. A substantial portion of lands submerged by reservoirs is held under flood right
easements.
I-33
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. Alabama Power (United States District Court for the Northern
District of Alabama)
United States of America v. Georgia Power (United States District Court for the Northern
District of Georgia)
See Note 3 to the financial statements of Southern Company and each traditional operating company
under Environmental Matters New Source Review Actions in Item 8 herein for information.
(2) Environmental Remediation
See Note 3 to the financial statements of Southern Company, Georgia Power, Gulf Power, and
Mississippi Power under Environmental Matters Environmental Remediation and Note 3 to the
financial statements of Mississippi Power under Retail Regulatory Matters Environmental
Compliance Overview Plan in Item 8 herein for information related to environmental remediation.
(3) Right of Way Litigation
See Note 3 to the financial statements of Southern Company and Mississippi Power under Right of
Way Litigation in Item 8 herein for information.
See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of
additional legal and administrative proceedings discussed therein.
I-34
EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with
Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of
December 31, 2010.
Thomas A. Fanning
Chairman, President, Chief Executive Officer, and Director
Age 53
Elected in 2003. Chairman and Chief Executive Officer since December 1, 2010 and President since
August 1, 2010. Previously served as Executive Vice President and Chief Operating Officer from
February 2008 through July 31, 2010. He also served as Executive Vice President and Chief
Financial Officer from May 2007 through January 2008 and Executive Vice President, Chief Financial
Officer, and Treasurer from April 2003 to May 2007.
Art P. Beattie
Executive Vice President and Chief Financial Officer
Age 56
Elected in 2010. Executive Vice President and Chief Financial Officer since August 13, 2010.
Previously served as Executive Vice President, Chief Financial Officer, and Treasurer of Alabama
Power from February 2005 through August 12, 2010 and Vice President and Comptroller of Alabama
Power from 1998 through January 2005.
W. Paul Bowers
Executive Vice President
Age 54
Elected in 2001. Chief Executive Officer, President and Director of Georgia Power since December
31, 2010 and Chief Operating Officer of Georgia Power from August 13, 2010 to December 31, 2010.
He previously served as Executive Vice President and Chief Financial Officer of Southern Company
from February 2008 to August 12, 2010. He also served as Executive Vice President of Southern
Company from May 2007 to February 2008 and as President of Southern Company Generation, a business
unit of Southern Company, and Executive Vice President of SCS from May 2001 through January 2008.
Mark A. Crosswhite
President and Chief Executive Officer of Gulf Power
Age 48
Elected in 2010. President, Chief Executive Officer, and Director of Gulf Power since January 1,
2011. Previously served as Executive Vice President of External Affairs at Alabama Power from
February 2008 through December 2010 and Senior Vice President and Counsel of Alabama Power from
July 2006 through January 2008. He also served as Vice President of SCS from March 2004 through
January 2008.
Edward Day, IV
President and Chief Executive Officer of Mississippi Power
Age 50
Elected in 2010. President, Chief Executive Officer, and Director of Mississippi Power since
August 13, 2010. Previously served as Executive Vice President for Engineering and Construction
Services at Southern Company Generation, a business unit of Southern Company, from May 2003 to
August 12, 2010.
G. Edison Holland, Jr.
Executive Vice President, General Counsel, and Secretary
Age 58
Elected in 2001. Executive Vice President and General Counsel since April 2001.
Charles D. McCrary
Executive Vice President
Age 59
Elected in 1998. Executive Vice President since February 2002. He also serves as President, Chief
Executive Officer, and Director of Alabama Power since October 2001.
I-35
James H. Miller, III
President and Chief Executive Officer of Southern Nuclear
Age 61
Elected in 2008. President and Chief Executive Officer of Southern Nuclear since August 27, 2008.
Previously served as Senior Vice President and General Counsel of Georgia Power from March 2004
through August 2008.
Susan N. Story
Executive Vice President
Age 50
Elected in 2003. President and Chief Executive Officer of SCS since January 1, 2011. Previously
served as President, Chief Executive Officer, and Director of Gulf Power from April 2003 through
December 2010.
Anthony J. Topazi
Executive Vice President and Chief Operating Officer
Age 60
Elected in 2003. Executive Vice President and Chief Operating Officer since August 13, 2010.
Previously served as President, Chief Executive Officer, and Director of Mississippi Power from
January 2004 through August 12, 2010.
Christopher C. Womack
Executive Vice President
Age 52
Elected in 2008. Executive Vice President and President of External Affairs since January 1, 2009.
Previously served as Executive Vice President of External Affairs of Georgia Power from March 2006
through December 2008 and Senior Vice President of Fossil and Hydro Generation and Senior
Production Officer of Georgia Power from December 2001 to February 2006.
The officers of Southern Company were elected for a term running from the first meeting of the
directors following the last annual meeting (May 26, 2010) for one year until the first board
meeting after the next annual meeting or until their successors are elected and have qualified,
except for Ms. Story, whose election was effective January 1, 2011, and Messrs. Beattie, and
Topazi, whose elections were effective August 13, 2010. Mr. Fanning was elected President effective August 1,
2010 and Chairman, President, Chief Executive Officer, and Director effective December 1, 2010.
I-36
EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with
Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of
December 31, 2010.
Charles D. McCrary
President, Chief Executive Officer, and Director
Age 59
Elected in 2001. President, Chief Executive Officer, and Director since October 2001; Executive
Vice President of Southern Company since February 2002.
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
Age 51
Elected in 2010. Executive Vice President, Chief Financial Officer and Treasurer since August 13,
2010. Previously served as Vice President and Chief Financial Officer of Gulf Power from May 2008
to August 12, 2010 and as Vice President and Comptroller of Alabama Power from January 2005 to
April 2008.
Zeke W. Smith
Executive Vice President
Age 51
Elected in 2010. Executive Vice President of External Affairs since November 8, 2010. Previously
served as Vice President of Regulatory Services and Financial Planning from February 2005 to
November 2010.
Steven R. Spencer
Executive Vice President
Age 55
Elected in 2001. Executive Vice President of the Customer Service Organization since February 1,
2008. Previously served as Executive Vice President of External Affairs from 2001 through January
2008.
Theodore J. McCullough
Senior Vice President and Senior Production Officer
Age 47
Elected in 2010. Senior Vice President and Senior Production Officer since June 30, 2010.
Previously served as Vice President and Senior Production Officer of Gulf Power from September 2007
until June 2010, and Manager of Georgia Powers Plant Branch from December 2003 to August 2007.
The officers of Alabama Power were elected for a term running from the meeting of the directors
held on April 23, 2010 for one year or until their successors are elected and have qualified,
except for Messrs. Raymond, Smith, and McCullough, whose elections were effective August 13, 2010,
November 8, 2010, and June 30, 2010, respectively.
I-37
EXECUTIVE OFFICERS OF GEORGIA POWER
(Identification of executive officers of Georgia Power is inserted in Part I in accordance with
Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of
December 31, 2010.
W. Paul Bowers
President, Chief Executive Officer, and Director
Age 54
Elected in 2010. Chief Executive Officer, President, and Director since December 31, 2010 and
Chief Operating Officer of Georgia Power from August 13, 2010 to December 31, 2010. He previously
served as Executive Vice President and Chief Financial Officer of Southern Company from February
2008 to August 12, 2010. He also served as Executive Vice President of Southern Company from May
2007 to February 2008 and as President of Southern Company Generation, a business unit of Southern
Company, and Executive Vice President of SCS from May 2001 through January 2008.
W. Craig Barrs
Executive Vice President
Age 53
Elected in 2008. Executive Vice President of External Affairs since January 2010. Previously
served as Senior Vice President of External Affairs from January 2009 to January 2010, Vice
President of Governmental and Regulatory Affairs from April 2008 to December 2008, Vice President
of the Coastal Region from August 2006 to March 2008, and President and Chief Executive Officer of
Savannah Electric and Power Company from January 2006 until its merger with and into Georgia Power
which was completed in July 2006.
Mickey A. Brown
Executive Vice President
Age 63
Elected in 2001. Executive Vice President of the Customer Service Organization since January 2005.
Ronnie R. Labrato
Executive Vice President, Chief Financial Officer, and Treasurer
Age 57
Elected in 2009. Executive Vice President, Chief Financial Officer, and Treasurer since April
2009. Previously served as Vice President of Internal Auditing at SCS from April 2008 to March
2009 and Vice President and Chief Financial Officer of Gulf Power from July 2001 to March 2008.
Joseph A. Miller
Executive Vice President
Age 49
Elected in 2009. Executive Vice President of Nuclear Development since May 2009. Also serves as
Executive Vice President of Nuclear Development at Southern Nuclear since February 2006.
Previously served as Vice President of Government Relations at SCS from May 1999 to January 2006.
Thomas P. Bishop
Senior Vice President, Chief Compliance Officer, and General Counsel
Age 50
Elected in 2008. Senior Vice President, Chief Compliance Officer, and General Counsel since
September 2008. Previously served as Vice President and Associate General Counsel for SCS from
July 2004 to September 2008.
I-38
Stan W. Connally
Senior Vice President and Chief Production Officer
Age 41
Elected in 2010. Senior Vice President and Chief Production Officer since August 1, 2010.
Previously served as Manager of Alabama Powers Plant Barry from August 2007 through July 2010 and
Manager of Mississippi Powers Plant Daniel from November 2004 through August 2007.
The officers of Georgia Power were elected for a term running from the meeting of the directors
held on May 19, 2010 for one year or until their successors are elected and have qualified, except
for Messrs. Bowers and Connally. Mr. Bowers was elected Chief Operating Officer effective August
13, 2010 and Chief Executive Officer, President, and Director effective December 31, 2010. Mr.
Connally was elected effective August 1, 2010.
I-39
EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with
Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of
December 31, 2010.
Edward Day, VI
President, Chief Executive Officer, and Director
Age 50
Elected in 2010. President, Chief Executive Officer, and Director since August 13, 2010.
Previously served as Executive Vice President for Engineering and
Construction Services at Southern
Company Generation, a business unit of Southern Company, from May 2003 to August 12, 2010.
Thomas O. Anderson, IV
Vice President
Age 51
Elected in 2009. Vice President of Generation Development since July 2009. Previously served as
Project Director, Mississippi Power Generation Development from March 2008 to July 2009; Project
Manager, Southern Power Generation from June 2007 to March 2008; and Generation Development
Manager, SCS Generation Development from September 1998 to June 2007.
John W. Atherton
Vice President
Age 50
Elected in 2004. Vice President of External Affairs since January 2005.
Moses H. Feagin
Vice President, Treasurer, and
Chief Financial Officer
Age 46
Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 13, 2010.
Previously served as Vice President and Comptroller of Alabama Power from May 2008 to August 12,
2010, and Comptroller of Mississippi Power from March 2005 to May 2008.
Donald R. Horsley
Vice President
Age 56
Elected in 2006. Vice President of Customer Services Organization since April 2006. Previously
served as Vice President of Transmission at Alabama Power from March 2005 to March 2006.
R. Allen Reaves
Vice President
Age 51
Elected in 2010. Vice President and Senior Production Officer since August 1, 2010. Previously
served as Manager of Mississippi Powers Plant Daniel from September 2007 through July 2010 and
Site Manager for Southern Powers Plant Franklin, from March 2006 to September 2007.
The officers of Mississippi Power were elected for a term running from the meeting of the directors
held on
April 8, 2010 for one year or until their successors are elected and have qualified, except for
Messrs. Day and Feagin, whose elections were effective August 13, 2010, and Mr. Reaves, whose
election was effective August 1, 2010.
I-40
PART II
|
|
|
Item 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
(a)(1) 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 |
2010 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
33.73 |
|
|
|
30.85 |
|
Second Quarter |
|
|
35.45 |
|
|
|
32.04 |
|
Third Quarter |
|
|
37.73 |
|
|
|
33.00 |
|
Fourth Quarter |
|
|
38.62 |
|
|
|
37.10 |
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
37.62 |
|
|
$ |
26.48 |
|
Second Quarter |
|
|
32.05 |
|
|
|
27.19 |
|
Third Quarter |
|
|
32.67 |
|
|
|
30.27 |
|
Fourth Quarter |
|
|
34.47 |
|
|
|
30.89 |
|
|
There is no market for the other registrants common stock, all of which is owned by Southern
Company.
(a)(2) Number of Southern Companys common stockholders of record at January 31, 2011: 159,733
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrants common stock are payable at the discretion of their
respective board of directors. The dividends on common stock declared by Southern Company and the
traditional operating companies to their stockholder(s) for the past two years were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Registrant |
|
Quarter |
|
2010 |
|
2009 |
|
|
|
|
(in thousands) |
Southern Company |
|
First |
|
$ |
359,144 |
|
|
$ |
326,780 |
|
|
|
Second |
|
|
375,865 |
|
|
|
343,446 |
|
|
|
Third |
|
|
378,939 |
|
|
|
348,702 |
|
|
|
Fourth |
|
|
382,440 |
|
|
|
350,538 |
|
|
|
|
|
|
|
|
|
|
|
|
Alabama Power |
|
First |
|
|
135,675 |
|
|
|
130,700 |
|
|
|
Second |
|
|
135,675 |
|
|
|
130,700 |
|
|
|
Third |
|
|
135,675 |
|
|
|
130,700 |
|
|
|
Fourth |
|
|
178,675 |
|
|
|
130,700 |
|
|
|
|
|
|
|
|
|
|
|
|
Georgia Power |
|
First |
|
|
205,000 |
|
|
|
184,725 |
|
|
|
Second |
|
|
205,000 |
|
|
|
184,725 |
|
|
|
Third |
|
|
205,000 |
|
|
|
184,725 |
|
|
|
Fourth |
|
|
205,000 |
|
|
|
184,725 |
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Power |
|
First |
|
|
26,075 |
|
|
|
22,325 |
|
|
|
Second |
|
|
26,075 |
|
|
|
22,325 |
|
|
|
Third |
|
|
26,075 |
|
|
|
22,325 |
|
|
|
Fourth |
|
|
26,075 |
|
|
|
22,325 |
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi Power |
|
First |
|
|
17,150 |
|
|
|
17,125 |
|
|
|
Second |
|
|
17,150 |
|
|
|
17,125 |
|
|
|
Third |
|
|
17,150 |
|
|
|
17,125 |
|
|
|
Fourth |
|
|
17,150 |
|
|
|
17,125 |
|
II-1
In 2010 and 2009, Southern Power paid dividends to Southern Company as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Registrant |
|
Quarter |
|
2010 |
|
2009 |
|
|
|
|
(in thousands) |
Southern Power |
|
First |
|
$ |
26,775 |
|
|
$ |
26,525 |
|
|
|
Second |
|
|
26,775 |
|
|
|
26,525 |
|
|
|
Third |
|
|
26,775 |
|
|
|
26,525 |
|
|
|
Fourth |
|
|
26,775 |
|
|
|
26,525 |
|
|
The dividend paid per share of Southern Companys common stock was 43.75¢ for the first quarter of
2010 and 45.50¢ for the second, third, and fourth quarters of 2010. In 2009, Southern Company paid
a dividend per share of 42¢ in the first quarter of 2009 and 43.75¢ for the second, third, and
fourth quarters of 2009.
The traditional operating companies and Southern Power can only pay dividends to Southern Company
out of retained earnings or paid-in-capital.
Southern Powers credit facility and senior note indenture contain potential limitations on the
payment of common stock dividends. At December 31, 2010, Southern Power was in compliance with the
conditions of this credit facility and thus had no restrictions on its ability to pay common stock
dividends. See Note 8 to the financial statements of Southern Company under Common Stock Dividend
Restrictions and Note 6 to the financial statements of Southern Power under Dividend
Restrictions in Item 8 herein for additional information regarding these restrictions.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
|
|
|
Item 6. |
|
SELECTED FINANCIAL DATA |
Southern Company. See SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA, contained herein
at pages II-103 and II-104.
Alabama Power. See SELECTED FINANCIAL AND OPERATING DATA, contained herein at pages II-178 and
II-179.
Georgia Power. See SELECTED FINANCIAL AND OPERATING DATA, contained herein at pages II-258 and
II-259.
Gulf Power. See SELECTED FINANCIAL AND OPERATING DATA, contained herein at pages II-328 and
II-329.
Mississippi Power. See SELECTED FINANCIAL AND OPERATING DATA, contained herein at pages II-409
and II-410.
Southern Power. See SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA, contained herein at page
II-458.
|
|
|
Item 7. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Southern Company. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS, contained herein at pages II-11 through II-43.
Alabama Power. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, contained herein at pages II-108 through II-132.
Georgia Power. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, contained herein at pages II-183 through II-210.
II-2
Gulf Power. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, contained herein at pages II-263 through II-286.
Mississippi Power. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, contained herein at pages II-333 through II-362.
Southern Power. See MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, contained herein at pages II-414 through II-433.
|
|
|
Item 7A. |
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See MANAGEMENTS DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY Market Price
Risk of each of the registrants in Item 7 herein and Note 1 of each of the registrants financial
statements under Financial Instruments in Item 8 herein. See also Note 10 to the financial
statements of Southern Company, Alabama Power, and Georgia Power, Note 9 to the financial
statements of Gulf Power and Mississippi Power, and Note 8 to the financial statements of Southern
Power in Item 8 herein.
II-3
|
|
|
Item 8. |
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO 2010 FINANCIAL STATEMENTS
|
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|
Page |
|
|
|
|
|
|
|
|
II-9 |
|
|
II-10 |
|
|
II-44 |
|
|
II-45 |
|
|
II-46 |
|
|
II-48 |
|
|
II-50 |
|
|
II-51 |
|
|
II-52 |
|
|
|
|
|
|
|
|
|
|
|
|
II-106 |
|
|
II-107 |
|
|
II-133 |
|
|
II-134 |
|
|
II-135 |
|
|
II-137 |
|
|
II-139 |
|
|
II-140 |
|
|
II-141 |
|
|
|
|
|
|
|
|
|
|
|
|
II-181 |
|
|
II-182 |
|
|
II-211 |
|
|
II-212 |
|
|
II-213 |
|
|
II-215 |
|
|
II-216 |
|
|
II-217 |
|
|
II-218 |
|
|
|
|
|
|
|
|
|
|
|
|
II-261 |
|
|
II-262 |
|
|
II-287 |
|
|
II-288 |
|
|
II-289 |
|
|
II-291 |
|
|
II-292 |
|
|
II-293 |
|
|
II-294 |
II-4
|
|
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|
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|
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Page |
|
|
|
|
|
|
|
|
II-331 |
|
|
II-332 |
|
|
II-363 |
|
|
II-364 |
|
|
II-365 |
|
|
II-367 |
|
|
II-368 |
|
|
II-369 |
|
|
II-370 |
|
|
|
|
|
|
|
|
|
|
|
|
II-412 |
|
|
II-413 |
|
|
II-434 |
|
|
II-435 |
|
|
II-436 |
|
|
II-438 |
|
|
II-439 |
|
|
II-440 |
|
|
|
Item 9. |
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
II-5
|
|
|
Item 9A. |
|
CONTROLS AND PROCEDURES |
Disclosure Controls And Procedures.
As of the end of the period covered by this annual report, Southern Company, Alabama Power, Georgia
Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the
supervision and with the participation of each companys management, including the Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and operation of the
disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the
Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are
effective.
Internal Control Over Financial Reporting.
(a) Managements Annual Report on Internal Control Over Financial Reporting.
Southern Companys Managements Report on Internal Control Over Financial Reporting is included on
page II-9 of this Form 10-K.
Alabama Powers Managements Report on Internal Control Over Financial Reporting is included on
page II-106 of this Form 10-K.
Georgia Powers Managements Report on Internal Control Over Financial Reporting is included on
page II-181 of this Form 10-K.
Gulf Powers Managements Report on Internal Control Over Financial Reporting is included on page
II-261 of this Form 10-K.
Mississippi Powers Managements Report on Internal Control Over Financial Reporting is included on
page II-331 of this Form 10-K.
Southern Powers Managements Report on Internal Control Over Financial Reporting is included on
page II-412 of this Form 10-K.
(b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Companys independent registered public accounting
firm, regarding Southern Companys internal control over financial reporting is included on page
II-10 of this Form 10-K.
Not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
because these companies are not accelerated filers.
(c) Changes in internal controls.
There have been no changes in Southern Companys, Alabama Powers, Georgia Powers, Gulf Powers,
Mississippi Powers, or Southern Powers internal control over financial reporting (as such term is
defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the
fourth quarter 2010 that have materially affected or are reasonably likely to materially affect
Southern Companys, Alabama Powers, Georgia Powers, Gulf Powers, Mississippi Powers, or
Southern Powers internal control over financial reporting.
II-6
|
|
|
Item 9B. |
|
OTHER INFORMATION |
Southern Company
Southern Company, SCS, and Thomas A. Fanning entered into an amendment to Mr. Fannings Amended and
Restated Change in Control Agreement, which terminates such agreement, effective February 22, 2011.
Following the termination, Mr. Fanning is a participant in the Amended and Restated Senior
Executive Change in Control Severance Plan. The Amendment is filed herewith as Exhibit 10(a)14.
Southern
Company, SCS, and W. Paul Bowers entered into an amendment to Mr. Bowers Amended and
Restated Change in Control Agreement, which terminates such agreement, effective February 22, 2011.
Following the termination, Mr. Bowers is a participant in the Amended and Restated Senior
Executive Change in Control Severance Plan. The amendment is filed herewith as Exhibit 10(a)18.
Southern Company, Alabama Power, and Charles D. McCrary entered into an amendment to Mr. McCrarys
Amended and Restated Change in Control Agreement, which terminates such agreement, effective
February 22, 2011. Following the termination, Mr. McCrary is a participant in the Amended and
Restated Senior Executive Change in Control Severance Plan. The amendment is filed herewith as
Exhibit 10(a)8.
Effective
February 23, 2011, The Southern Company Senior Executive Change in
Control Severance Plan (Plan) was amended to reduce the severance benefit provided to all executive
officers of Southern Company, except the Chief Executive Officer, from three times salary plus
annual performance-based compensation target opportunity to two times that amount. The amendment
also provides that any severance payment under the Plan shall not exceed three times a
participants base amount as such term is defined under Section 280G of the Code. The amendment to
the Plan is filed herewith as Exhibit 10(a)16.
On February 22, 2011, Georgia Power entered into a Separation and Release Agreement with Michael D.
Garrett in connection with his retirement from Georgia Power. Under the agreement, Georgia Power
will pay Mr. Garrett a severance payment of $1,000,000.00. The agreement contains standard
non-compete and confidentiality terms and a legal release. The agreement is filed herewith as
Exhibit 10(a)9.
II-7
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-8
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2010 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, 2010.
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, 2010. Deloitte & Touche
LLPs report on Southern Companys internal control over financial reporting is included herein.
/s/ Thomas A. Fanning
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President and Chief Financial Officer
February 25, 2011
II-9
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, 2010
and 2009, 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, 2010. Our
audits also included the financial statement schedule of the Company listed in the Index at Item 15. We also have
audited the Companys internal control over financial reporting as of December 31, 2010, 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 and the financial statement schedule, 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 II-9). Our responsibility is to express an opinion on these financial
statements and the financial statement schedule 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 II-44 to II-101) referred to above
present fairly, in all material respects, the financial position of Southern Company and Subsidiary
Companies as of December 31, 2010 and 2009, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2010, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion,
the financial statement schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the information set forth
therein. Also, in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2010, 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, 2011
II-10
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2010 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 and grow energy sales given economic conditions,
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. 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). 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 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 2010 Peak Season EFOR of 1.67% was better than the target.
Transmission and distribution system reliability performance is measured by the frequency and
duration of outages. Performance targets for reliability are set internally based on historical
performance, expected weather conditions, and expected capital expenditures. The performance for
2010 was better than the target for these reliability measures.
Southern Companys 2010 results compared with its targets for some of these key indicators are
reflected in the following chart:
|
|
|
|
|
|
|
|
|
|
|
2010 Target |
|
2010 Actual |
Key Performance Indicator |
|
Performance |
|
Performance |
|
|
Top quartile in |
|
|
Customer Satisfaction |
|
customer surveys |
|
Top quartile |
Peak Season EFOR fossil/hydro |
|
5.06% or less |
|
|
1.67 |
% |
Basic EPS |
|
$2.30 $2.36 |
|
$ |
2.37 |
|
See RESULTS OF OPERATIONS herein for additional information on the Companys financial performance.
The performance achieved in 2010 reflects the continued emphasis that management places on these
indicators as well as the commitment shown by employees in achieving or exceeding managements
expectations.
II-11
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Earnings
Southern Companys net income after dividends on preferred and preference stock of subsidiaries was
$1.98 billion in 2010, an increase of $332 million from the prior year. This increase was
primarily the result of increases in revenues due to colder weather in the first and fourth
quarters 2010 and warmer weather in the second and third quarters 2010, a litigation settlement
agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increased
amortization of the regulatory liability related to other cost of removal obligations at Georgia
Power as authorized by the Georgia Public Service Commission (PSC), revenues associated with
increases in rates under Alabama Powers rate stabilization and equalization plan (Rate RSE) and
rate certificated new plant environmental (Rate CNP Environmental) that took effect in January
2010, and increases in sales primarily in the industrial sector. The 2010 increase was partially
offset by increases in operations and maintenance expenses, which include an additional accrual to
Alabama Powers natural disaster reserve (NDR), a gain in 2009 on the early termination of two
leveraged lease investments, and an increase in depreciation on additional plant in service related
to environmental, distribution, and transmission projects. Net income after dividends on preferred
and preference stock of subsidiaries was $1.64 billion in 2009 and $1.74 billion in 2008.
Basic EPS was $2.37 in 2010, $2.07 in 2009, and $2.26 in 2008. Diluted EPS, which factors in
additional shares related to stock-based compensation, was $2.36 in 2010, $2.06 in 2009, and $2.25
in 2008. EPS for 2010 was negatively impacted by $0.12 per share as a result of an increase in the
average shares outstanding.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of
common stock were $1.8025 in 2010, $1.7325 in 2009, and $1.6625 in 2008. In January 2011, Southern
Company declared a quarterly dividend of 45.50 cents per share. This is the 253rd 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 70% of net income. For 2010, the
actual payout ratio was 76%.
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 |
|
|
|
2010 |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Electric operating revenues |
|
$ |
17,374 |
|
|
$ |
1,732 |
|
|
$ |
(1,358 |
) |
|
$ |
1,860 |
|
|
Fuel |
|
|
6,699 |
|
|
|
747 |
|
|
|
(865 |
) |
|
|
973 |
|
Purchased power |
|
|
563 |
|
|
|
89 |
|
|
|
(341 |
) |
|
|
300 |
|
Other operations and maintenance |
|
|
3,907 |
|
|
|
505 |
|
|
|
(183 |
) |
|
|
111 |
|
Depreciation and amortization |
|
|
1,494 |
|
|
|
19 |
|
|
|
62 |
|
|
|
199 |
|
Taxes other than income taxes |
|
|
867 |
|
|
|
51 |
|
|
|
22 |
|
|
|
56 |
|
|
Total electric operating expenses |
|
|
13,530 |
|
|
|
1,411 |
|
|
|
(1,305 |
) |
|
|
1,639 |
|
|
Operating income |
|
|
3,844 |
|
|
|
321 |
|
|
|
(53 |
) |
|
|
221 |
|
Other income (expense), net |
|
|
159 |
|
|
|
(41 |
) |
|
|
53 |
|
|
|
26 |
|
Interest expense, net of amounts
capitalized |
|
|
833 |
|
|
|
(2 |
) |
|
|
61 |
|
|
|
10 |
|
Income taxes |
|
|
1,116 |
|
|
|
128 |
|
|
|
(49 |
) |
|
|
87 |
|
|
Net income |
|
|
2,054 |
|
|
|
154 |
|
|
|
(12 |
) |
|
|
150 |
|
Dividends on preferred and
preference stock of subsidiaries |
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
Net income after dividends on
preferred and preference stock
of subsidiaries |
|
$ |
1,989 |
|
|
$ |
154 |
|
|
$ |
(12 |
) |
|
$ |
133 |
|
|
II-12
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Electric Operating Revenues
Details of electric operating revenues were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(in millions) |
Retail prior year |
|
$ |
13,307 |
|
|
$ |
14,055 |
|
|
$ |
12,639 |
|
Estimated change in |
|
|
|
|
|
|
|
|
|
|
|
|
Rates and pricing |
|
|
384 |
|
|
|
144 |
|
|
|
668 |
|
Sales growth (decline) |
|
|
32 |
|
|
|
(208 |
) |
|
|
|
|
Weather |
|
|
439 |
|
|
|
(21 |
) |
|
|
(106 |
) |
Fuel and other cost recovery |
|
|
629 |
|
|
|
(663 |
) |
|
|
854 |
|
|
Retail current year |
|
|
14,791 |
|
|
|
13,307 |
|
|
|
14,055 |
|
Wholesale revenues |
|
|
1,994 |
|
|
|
1,802 |
|
|
|
2,400 |
|
Other electric operating revenues |
|
|
589 |
|
|
|
533 |
|
|
|
545 |
|
|
Electric operating revenues |
|
$ |
17,374 |
|
|
$ |
15,642 |
|
|
$ |
17,000 |
|
|
Percent change |
|
|
11.1 |
% |
|
|
(8.0 |
%) |
|
|
12.3 |
% |
|
Retail revenues increased $1.5 billion, decreased $748 million, and increased $1.4 billion in 2010,
2009, and 2008, respectively. The significant factors driving these changes are shown in the
preceding table. The increase in rates and pricing in 2010 was primarily due to Rate RSE and Rate
CNP Environmental increases at Alabama Power and the recovery of environmental costs at Gulf Power.
The 2009 increase in rates and pricing when compared to the prior year was primarily due to an
increase in revenues from customer charges at Alabama Power and increased 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), 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 RSE, as ordered by the Alabama PSC, and Georgia Powers increase under the
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.
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. Wholesale revenues from PPAs and unit
power sales contracts have both capacity and energy components. Capacity revenues reflect the
recovery of fixed costs and a return on investment. Energy revenues will vary depending on the
market cost of available energy compared to the cost of the Companys system-owned generation, demand for
energy within the Companys service territory, and the availability of the Companys system
generation. Increases and decreases in energy revenues that are driven by fuel prices are
accompanied by an increase or decrease in fuel costs and do not have a significant impact on net
income.
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 2010, wholesale revenues increased $192 million primarily due to higher capacity and energy
revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July
2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more
favorable weather. This increase was partially offset by the expiration of long-term unit power
sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made
available for retail service starting in June 2010. See FUTURE EARNINGS POTENTIAL PSC Matters
Alabama Power Rate CNP herein for additional information regarding the termination of
certain unit power sales contracts in 2010.
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.
II-13
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
In 2008, wholesale revenues increased $412 million primarily as a result of a 21.8% increase in the
average cost of fuel per net kilowatt-hour (KWH) generated, as well as revenues resulting from new
and existing PPAs and revenues derived from contracts for Southern 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.
Revenues associated with PPAs and opportunity sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Other power sales |
|
|
|
|
|
|
|
|
|
|
|
|
Capacity and other |
|
$ |
684 |
|
|
$ |
575 |
|
|
$ |
538 |
|
Energy |
|
|
1,034 |
|
|
|
735 |
|
|
|
1,319 |
|
|
Total |
|
$ |
1,718 |
|
|
$ |
1,310 |
|
|
$ |
1,857 |
|
|
KWH sales under unit power sales contracts decreased 55.0%, 7.5%, and 2.1% in 2010, 2009, and 2008,
respectively. See FUTURE EARNINGS POTENTIAL PSC Matters Alabama Power Rate CNP herein
for additional information regarding the termination of certain unit power sales contracts in 2010,
which resulted in a decrease in capacity and energy revenues. In addition, fluctuations in oil and
natural gas prices, which are the primary fuel sources for unit power sales contracts, influence
changes in energy sales. However, because the energy is generally sold at variable cost,
fluctuations in energy sales have a minimal effect on earnings. The capacity and energy components
of the unit power sales contracts were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
2008 |
|
|
(in millions) |
Unit power sales |
|
|
|
|
|
|
|
|
|
|
|
|
Capacity |
|
$ |
136 |
|
|
$ |
225 |
|
|
$ |
223 |
|
Energy |
|
|
140 |
|
|
|
267 |
|
|
|
320 |
|
|
Total |
|
$ |
276 |
|
|
$ |
492 |
|
|
$ |
543 |
|
|
Other Electric Revenues
Other electric revenues increased $56 million, decreased $12 million, and increased $32 million in
2010, 2009, and 2008, respectively. Other electric revenues increased in 2010 primarily as a
result of a $38 million increase in transmission revenues, a $4 million increase in rents from
electric property, a $4 million increase in outdoor lighting revenues, and a $4 million increase in
late fees. The 2009 decrease in other electric revenues was not material when compared to 2008.
The 2008 increase in other electric revenues was not material when compared to 2007.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to
year. KWH sales for 2010 and the percent change by year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Total KWH |
|
|
Weather-Adjusted |
|
|
|
KWHs |
|
|
Percent Change |
|
|
Percent Change |
|
|
|
2010 |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in billions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
57.8 |
|
|
|
11.8 |
% |
|
|
(1.1 |
)% |
|
|
(2.0 |
)% |
|
|
0.2 |
% |
|
|
(0.7 |
)% |
|
|
0.0 |
% |
Commercial |
|
|
55.5 |
|
|
|
3.7 |
|
|
|
(1.7 |
) |
|
|
(0.4 |
) |
|
|
(0.6 |
) |
|
|
(1.2 |
) |
|
|
1.0 |
|
Industrial |
|
|
50.0 |
|
|
|
7.7 |
|
|
|
(11.8 |
) |
|
|
(3.7 |
) |
|
|
7.1 |
|
|
|
(11.7 |
) |
|
|
(3.5 |
) |
Other |
|
|
0.9 |
|
|
|
(1.0 |
) |
|
|
2.0 |
|
|
|
(2.9 |
) |
|
|
(1.5 |
) |
|
|
2.2 |
|
|
|
(2.7 |
) |
|
|
|
Total retail |
|
|
164.2 |
|
|
|
7.6 |
|
|
|
(4.8 |
) |
|
|
(2.1 |
) |
|
|
2.0 |
% |
|
|
(4.5 |
)% |
|
|
(0.9 |
)% |
|
|
|
Wholesale |
|
|
32.6 |
|
|
|
(2.8 |
) |
|
|
(14.9 |
) |
|
|
(3.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total energy sales |
|
|
196.8 |
|
|
|
5.7 |
% |
|
|
(6.8 |
)% |
|
|
(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 increased 11.6 billion
KWHs in 2010. This increase was primarily the result of colder weather in the first and fourth
quarters 2010 and warmer weather in the second and third quarters 2010, increased industrial KWH
sales, and customer growth of 0.3%. Increased demand in the primary metals, chemicals, and transportations sectors were the
main contributors to the increase in industrial KWH sales. Retail energy sales decreased 7.7
billion KWHs in 2009 primarily as a result of lower usage by industrial
II-14
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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%.
Wholesale energy sales decreased by 0.9 billion KWHs in 2010, decreased by 5.9 billion KWHs in
2009, and decreased by 1.4 billion KWHs in 2008. The decrease in wholesale energy sales in 2010
was primarily related to the expiration of long-term unit power sales contracts in May 2010 at
Alabama Power and the capacity subject to those contracts being made available for retail service
starting in June 2010. This decrease was partially offset by
increased energy sales
under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as
well as sales that were not covered by PPAs at Southern Power primarily due to more favorable
weather in 2010 compared to 2009. 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 at Southern Power being placed in operation in December 2007 and
June 2008, respectively.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
Total generation (billions of KWHs) |
|
|
196 |
|
|
|
187 |
|
|
|
198 |
|
Total purchased power (billions of KWHs) |
|
|
10 |
|
|
|
8 |
|
|
|
11 |
|
|
Sources of generation (percent) |
|
|
|
|
|
|
|
|
|
|
|
|
Coal |
|
|
58 |
|
|
|
57 |
|
|
|
68 |
|
Nuclear |
|
|
15 |
|
|
|
16 |
|
|
|
15 |
|
Gas |
|
|
25 |
|
|
|
23 |
|
|
|
16 |
|
Hydro |
|
|
2 |
|
|
|
4 |
|
|
|
1 |
|
|
Cost of fuel, generated (cents per net KWH) |
|
|
|
|
|
|
|
|
|
|
|
|
Coal |
|
|
3.93 |
|
|
|
3.70 |
|
|
|
3.27 |
|
Nuclear |
|
|
0.63 |
|
|
|
0.55 |
|
|
|
0.50 |
|
Gas |
|
|
4.27 |
|
|
|
4.58 |
|
|
|
7.58 |
|
|
Average cost of fuel, generated (cents per net KWH)* |
|
|
3.50 |
|
|
|
3.38 |
|
|
|
3.52 |
|
Average cost of purchased power (cents per net KWH) |
|
|
6.98 |
|
|
|
6.37 |
|
|
|
7.85 |
|
|
|
|
|
* |
|
Fuel includes fuel purchased by the electric utilities 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 2010, fuel and purchased power expenses were $7.3 billion, an increase of $836 million or
13.0% above 2009 costs. This increase was primarily the result of a $538 million increase in the
amount of total KWHs generated and purchased due primarily to increased customer demand. Also
contributing to this increase was a $298 million increase in the average cost per KWH generated and
purchased due primarily to a 3.6% increase in the cost per KWH generated and a 9.6% increase in the
cost per KWH purchased.
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.
II-15
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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.
From an overall global market perspective, coal prices increased substantially in 2010 from the
levels experienced in 2009, but remained lower than the unprecedented high levels of 2008. The
slowly recovering U.S. economy and global demand from coal importing countries drove the higher
prices in 2010, with concerns over regulatory actions, such as permitting issues, and their
negative impact on production also contributing upward pressure. Domestic natural gas prices
continued to be depressed by robust supplies, including production from shale gas, as well as lower
demand. These lower natural gas prices contributed to increased use of natural gas-fueled
generating units in 2009 and 2010. Uranium prices remained relatively constant during the early
portion of 2010 but rose steadily during the second half of the year. At year end, uranium prices
remained well below the highs set during 2007. Worldwide uranium production levels increased in
2010; 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 $3.9 billion, $3.4 billion, and $3.6 billion,
increasing $505 million, decreasing $183 million, and increasing $111 million in 2010, 2009, and
2008, respectively. Discussion of significant variances for components of other operations and
maintenance expenses follows.
Other production expenses at fossil, hydro, and nuclear plants increased $277 million, decreased
$70 million, and increased $63 million in 2010, 2009, and 2008, respectively. Production expenses
fluctuate from year to year due to variations in outage schedules and changes in the cost of labor
and materials. Other production expenses increased in 2010 mainly due to a $178 million increase
in outage and maintenance costs and an $86 million increase in commodity and labor costs,
reflecting a return to more normal spending levels when compared to 2009. Also contributing to
this increase was an $18 million increase in maintenance costs related to additional equipment
placed in service. Partially offsetting the 2010 increase was a $5 million loss recognized in 2009
on the transfer of Southern Powers Plant Desoto. Other production expenses 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. 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. See Note
1 to the financial statements under Property, Plant, and Equipment for additional information
regarding nuclear refueling costs.
Transmission and distribution expenses increased $143 million, decreased $41 million, and increased
$4 million in 2010, 2009, and 2008, 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 increased in 2010 primarily due to
increased spending on line clearing and other maintenance costs, reflecting a return to more normal
spending levels, as well as an additional accrual to Alabama Powers NDR. Transmission and
distribution expenses decreased in 2009 primarily related to lower planned spending, as well as
other cost containment activities, partially offset by an additional accrual to Alabama Powers
NDR. See FUTURE EARNINGS POTENTIAL PSC Matters Alabama Power Natural Disaster Reserve
herein for additional information. The 2008 increase in transmission and distribution expenses was
not material when compared to the prior year.
Customer sales and service expenses increased $18 million, decreased $42 million, and increased $32
million in 2010, 2009, and 2008, respectively. Customer sales and service expenses increased in
2010 primarily as a result of an $8 million increase in sales expenses, a $13 million increase in
customer service expense, a $10 million increase in records and collection, and a $3 million
increase in uncollectible accounts expense. Partially offsetting this increase was a $7 million
decrease in meter reading expenses and a $9 million decrease in other energy services. Customer
sales and service expenses decreased in 2009 primarily as a result of a $12
II-16
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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.
Administrative and general expenses increased $67 million, decreased $30 million, and increased $12
million in 2010, 2009, and 2008, respectively. Administrative and general expenses increased in
2010 primarily as a result of cost containment activities in 2009 which were taken to offset the
effects of the recessionary economy. The 2008 increase in administrative and general expenses was
not material when compared to 2007.
Depreciation and Amortization
Depreciation and amortization increased $19 million in 2010 primarily as the result of additional
depreciation on plant in service related to environmental, transmission, and distribution projects,
as well as additional depreciation at Southern Power. This increase was largely offset by a $133
million increase in the amortization of the regulatory liability related to other cost of removal
obligations at Georgia Power as authorized by the Georgia PSC. See Note 3 to the financial
statements under Retail Regulatory Matters Georgia Power Retail Rate Plans for additional
information regarding Georgia Powers cost of removal 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.
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 Southern Powers Plant Oleander Unit 5 in
December 2007 and Plant Franklin Unit 3 in June 2008.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $51 million in 2010 primarily due to higher municipal
franchise fees at Georgia Power as a result of increased retail revenues, increases in state and
municipal public utility license tax bases at Alabama Power, increases in gross receipts and
franchise fees at Gulf Power, increases in ad valorem taxes, and increases in payroll 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.
Other Income (Expense), Net
Other income (expense), net decreased $41 million in 2010 primarily due to a decrease in allowance
for funds used during construction (AFUDC) equity, mainly due to the completion of environmental
projects at Alabama Power and Gulf Power, and a $13 million profit recognized in 2009 at Southern
Power related to a construction contract with the OUC. The 2010 decrease was partially offset by
increases in AFUDC equity related to the increase in construction of three new combined cycle units
and two new nuclear generating units at Georgia Power. 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.
II-17
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Interest Expense, Net of Amounts Capitalized
Total interest charges and other financing costs decreased $2 million in 2010 primarily due to an
$18 million decrease related to lower average interest rates on existing variable rate debt, an $11
million decrease in other interest costs, and a $2 million increase in capitalized interest as
compared to 2009. The 2010 decrease was largely offset by a $29 million increase associated with
$1.0 billion in additional debt outstanding at December 31, 2010 compared to December 31, 2009.
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.
Income Taxes
Income taxes increased $128 million in 2010 primarily due to higher pre-tax earnings as compared to
2009, a decrease in the Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section
199 production activities deduction, and an increase in Alabama state taxes due to a decrease in
the state deduction for federal income taxes paid. Partially offsetting this increase were state
tax credits at Georgia Power and tax benefits associated with the construction of a biomass
facility at Southern Power. See Note 5 to the financial statements under Effective Tax Rate for
additional information.
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 federal production
activities deduction.
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.
Dividends on Preferred and Preference Stock of Subsidiaries
In both 2010 and 2009, dividends on preferred and preference stock of subsidiaries were flat
compared to the applicable 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.
Other Business Activities
Southern Companys other business activities include the parent company (which does not allocate
operating expenses to business units), investments in leveraged lease projects, and
telecommunications. These businesses are classified in general categories and may comprise one or
more of the following subsidiaries: Southern Company Holdings invests in various projects,
including leveraged lease projects; and SouthernLINC Wireless provides digital wireless
communications for use by Southern Company and its subsidiary companies and also markets these
services to the public and provides fiber cable services within the Southeast.
II-18
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
A condensed statement of income for Southern Companys other business activities follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
Amount |
|
from Prior Year |
|
|
2010 |
|
2010 |
|
2009 |
|
2008 |
|
|
(in millions) |
Operating revenues |
|
$ |
82 |
|
|
$ |
(19 |
) |
|
$ |
(26 |
) |
|
$ |
(86 |
) |
|
Other operations and maintenance |
|
|
103 |
|
|
|
(22 |
) |
|
|
(40 |
) |
|
|
(44 |
) |
MC Asset Recovery litigation settlement |
|
|
|
|
|
|
(202 |
) |
|
|
202 |
|
|
|
|
|
Depreciation and amortization |
|
|
19 |
|
|
|
(8 |
) |
|
|
(2 |
) |
|
|
(1 |
) |
Taxes other than income taxes |
|
|
2 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
Total operating expenses |
|
|
124 |
|
|
|
(232 |
) |
|
|
159 |
|
|
|
(45 |
) |
|
Operating income (loss) |
|
|
(42 |
) |
|
|
213 |
|
|
|
(185 |
) |
|
|
(41 |
) |
Equity in income (losses) of
unconsolidated subsidiaries |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
35 |
|
Leveraged lease income (losses) |
|
|
18 |
|
|
|
(22 |
) |
|
|
125 |
|
|
|
(125 |
) |
Other income (expense), net |
|
|
(16 |
) |
|
|
(19 |
) |
|
|
(8 |
) |
|
|
(31 |
) |
Interest expense |
|
|
62 |
|
|
|
(8 |
) |
|
|
(22 |
) |
|
|
(30 |
) |
Income taxes |
|
|
(90 |
) |
|
|
1 |
|
|
|
30 |
|
|
|
(7 |
) |
|
Net income (loss) |
|
$ |
(14 |
) |
|
$ |
178 |
|
|
$ |
(87 |
) |
|
$ |
(125 |
) |
|
Operating Revenues
Southern Companys non-electric operating revenues from these other businesses decreased $19
million in 2010 primarily as a result of a decrease in revenues at SouthernLINC Wireless related to
lower average revenue per subscriber and fewer subscribers due to increased competition in the
industry. The $26 million decrease in 2009 primarily resulted from 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 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.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other businesses decreased $22 million in 2010
primarily as a result of lower administrative and general expenses for these other businesses.
Other operations and maintenance expenses 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.
MC Asset Recovery Litigation Settlement
In March 2009, Southern Company entered into a litigation settlement agreement with MC Asset
Recovery which resulted in a charge of $202 million and required 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 had 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. In June 2009, the case was dismissed
with prejudice.
Equity in Income (Losses) of Unconsolidated Subsidiaries
Equity in income (losses) of unconsolidated subsidiaries for 2010 was flat when compared to the
prior year. 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
II-19
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
dissolution of a partnership that was associated with 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.
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) decreased $22 million in 2010
primarily as a result of a $26 million gain recorded in 2009 associated with the early termination
of two international leveraged lease investments, the proceeds from which were required to
extinguish all debt related to the leveraged lease investments, and a portion of which had
make-whole redemption provisions. This resulted in a $17 million loss in 2009, partially
offsetting the gain. In addition, leveraged lease income decreased $6 million in 2010 primarily
due to lease income no longer being recognized on the terminated leveraged lease 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.
Other Income (Expense), Net
Other income (expense), net for these other businesses decreased $19 million in 2010 primarily due
to charitable contributions made by the parent company. The 2009 change in other income (expense),
net 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.
Interest Expense
Total interest charges and other financing costs for these other businesses decreased $8 million in
2010 primarily due to lower average interest rates on existing variable rate debt. Total interest
charges and other financing costs 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.
Income Taxes
The 2010 increase in income taxes for these other businesses was not material when compared to the
prior year. Income taxes 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. 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
II-20
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
power. Southern Power is party to long-term contracts reflecting market-based rates, including
inflation expectations. Any adverse effect of inflation on Southern Companys results of
operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The four traditional operating companies operate as vertically integrated utilities providing
electricity to customers within their service areas in the Southeastern U.S. Prices for
electricity provided to retail customers are set by state PSCs under cost-based regulatory
principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the
exchange of electric power are regulated by the Federal Energy Regulatory Commission (FERC).
Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations.
Southern Power continues to focus on long-term capacity contracts, optimized by limited energy
trading activities. See ACCOUNTING POLICIES Application of Critical Accounting Policies and
Estimates Electric Utility Regulation herein and Note 3 to the financial statements for
additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future
earnings potential. The level of Southern 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 timely recovery of
prudently incurred costs during a time of increasing costs. Other major factors include
profitability of the competitive wholesale supply business and federal regulatory policy. 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.
Changes in economic conditions impact sales for the traditional operating companies and Southern
Power, and the pace of the economic recovery remains uncertain. The timing and extent of the
economic recovery will impact growth and may impact future earnings.
In 2010, Southern Company system generating capacity increased 30 megawatts due to the completion
of a solar photovoltaic plant near Cimarron, New Mexico. 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.
The timing, specific requirements, and estimated costs could 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
II-21
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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. The separate action against Alabama Power is ongoing.
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. On September
2, 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only
three claims for summary disposition or trial, including the claim relating to a facility co-owned
by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010.
The court has set a trial date for October 2011 for any remaining claims.
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. The ultimate
outcome of this matter cannot be determined at this time.
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, in September 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 December 6, 2010, the U.S.
Supreme Court granted the defendants petition for writ of certiorari. 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. In September 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. In November 2009, the plaintiffs filed an appeal with the U.S. Court of
Appeals for the Ninth
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Circuit challenging the district courts order dismissing the case. On January 24, 2011, the
defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling
the case pending the decision of the U.S. Supreme Court in the New York case discussed above. 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, as illustrated by the New York and Kivalina cases,
courts have been debating whether private parties and states have standing to bring such claims.
In another common law nuisance case, the U.S. District Court for the Southern District of
Mississippi dismissed private party claims against certain oil, coal, chemical, and utility
companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties
lacked standing to bring the claims and the claims were barred by the political question doctrine.
In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and
held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence
claims and none of the claims were barred by the political question doctrine. On May 28, 2010,
however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs appeal of the
case based on procedural grounds, reinstating the district court decision in favor of the
defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs petition to
reinstate the appeal. This case is now concluded.
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 2010, the electric utilities had invested approximately $8.1 billion in environmental
capital retrofit projects to comply with these requirements, with annual totals of $500 million,
$1.3 billion, and $1.6 billion for 2010, 2009, and 2008, respectively. The Company expects that
capital expenditures to comply with existing statutes and regulations will be $341 million, $427
million, and $452 million for 2011, 2012, and 2013, respectively. These environmental costs that
are known and estimable at this time are included under the heading Capital in the table under
FINANCIAL CONDITION AND LIQUIDITY Capital Requirements and Contractual Obligations herein. In
addition, the Company currently estimates that potential incremental investments to comply with
anticipated new environmental regulations could range from $74 million to $289 million in 2011,
$191 million to $670 million in 2012, and $476 million to $1.9 billion in 2013. The Companys
compliance strategy, including potential unit retirement and replacement decisions, and future
environmental capital expenditures will be affected by the final requirements of any new or revised
environmental statutes and regulations that are enacted, including the proposed environmental
legislation and regulations described below; the cost, availability, and existing inventory of
emissions allowances; and the fuel mix of the electric utilities.
Compliance with any new federal or state legislation or regulations relating to global climate
change, air quality, coal combustion byproducts, including coal ash, water quality, or other
environmental and health concerns could significantly affect the Company. Although new or revised
environmental legislation or regulations could affect many areas of the electric utilities
operations, the full impact of any such changes cannot be determined at this time. Additionally,
many of the electric utilities commercial and industrial customers may also be affected by
existing and future environmental requirements, which for some may have the potential to ultimately
affect their demand for electricity.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a
significant focus for Southern Company. Through 2010, the electric utilities had spent
approximately $7 billion in reducing sulfur dioxide (SO2) and nitrogen oxide
(NOx) emissions and in monitoring emissions pursuant to the Clean Air Act. As a result,
emissions control projects have been completed recently or are underway. Additional controls are
currently planned or under consideration to further reduce air emissions, maintain compliance with
existing regulations, and meet new requirements.
The EPA regulates ground level ozone concentrations 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
II-23
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
nonattainment for the current standard. On November 30, 2010, the EPA extended the attainment date
for this area by one year as a result of improving air quality. In March 2008, 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 level of the standard. Under the EPAs current schedule, a
final revision to the eight-hour ozone standard is expected in July 2011, with state implementation
plans for any resulting nonattainment areas due in mid-2014. The revised eight-hour ozone standard
is expected to result in designation of new nonattainment areas within Southern Companys service
territory, and could result in additional required reductions in NOx emissions.
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
implementation plans demonstrating attainment with the annual standard for all areas have been
submitted to the EPA. In September 2006, the EPA published a final rule which increased the
stringency of the 24-hour average fine particulate matter air quality standard. In October 2009,
the EPA designated the Birmingham area as nonattainment for the 24-hour standard. In April 2010,
the State of Alabama requested that the EPA re-designate Birmingham to attainment for the 24-hour
standard based on current air quality data. In September 2010, the EPA determined that Birmingham
has air quality data that meets the 24-hour standard. The EPA is expected to propose new annual
and 24-hour fine particulate matter standards during the summer of 2011.
Final revisions to the National Ambient Air Quality Standard for SO2, including the
establishment of a new one-hour standard, became effective on August 23, 2010. Since the EPA
intends to rely on computer modeling for implementation of the SO2 standard, the
identification of potential nonattainment areas remains uncertain and could ultimately include
areas within the Companys service territory. Implementation of the revised SO2
standard could result in additional required reductions in SO2 emissions and increased
compliance and operation costs.
Revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2), which
established a new one-hour standard, became effective on April 12, 2010. Although none of the
areas within Southern Companys service territory are expected to be designated as nonattainment
for the NO2 standard, based on current ambient air quality monitoring data, the new
NO2 standard could result in significant additional compliance and operational costs for
units that require new source permitting.
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 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 and operation of emissions controls at coal-fired facilities of
the electric utilities and/or by the purchase of emissions allowances.
On August 2, 2010, the EPA published a proposed rule, referred to as the Transport Rule, to replace
CAIR. This proposed rule would require 31 eastern states and the District of Columbia (D.C.) to
reduce power plant emissions of SO2 and NOx that contribute to downwind
states nonattainment of federal ozone and/or fine particulate matter ambient air quality
standards. To address fine particulate matter standards, the proposed Transport Rule would require
D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of
SO2 and NOx from power plants. To address ozone standards, the proposed
Transport Rule would also require D.C. and 25 states, including each of the states in Southern
Companys service territory, to achieve additional reductions in NOx emissions from
power plants during the ozone season. The proposed Transport Rule contains a preferred option
that would allow limited interstate trading of emissions allowances; however, the EPA also
requested comment on two alternative approaches that would not allow interstate trading of
emissions allowances. The EPA stated that it also intends to develop a second phase of the
Transport Rule in 2011 to address the more stringent ozone air quality standards after they are
finalized. The EPA expects to finalize the Transport Rule in June 2011 and require compliance
beginning in 2012.
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 visibility conditions goal by 2018 and for
each 10-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.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
The EPA is currently developing a Maximum Achievable Control Technology (MACT) rule for coal- and
oil-fired electric generating units which will establish emission limitations for numerous
hazardous air pollutants, including mercury. As part of a proceeding in the U.S. District Court
for the District of Columbia, the EPA has entered into a consent decree that requires the EPA to
issue a proposed MACT rule by March 16, 2011 and a final rule by November 16, 2011.
On April 29, 2010, the EPA issued a proposed Industrial Boiler (IB) MACT rule
that would establish
emissions limits for various hazardous air pollutants typically emitted from industrial boilers,
including biomass boilers and start-up boilers. The EPA issued the
final rules on February 23, 2011 and, at the same time, issued a
notice of intent to reconsider the final rules to allow for
additional public review and comment. The impact of these regulations will depend on their final form and the outcome of any
legal challenges and cannot be determined at this time.
The impacts of the eight-hour ozone, fine particulate matter, SO2 and NO2
standards, the proposed Transport Rule, the Clean Air Visibility Rule, and the proposed 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 pending
and future 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. 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.
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 to ensure continued compliance with applicable air
quality requirements.
In addition to the federal air quality laws described above, Georgia Power also is subject to the
requirements of the State of Georgias Multi-Pollutant Rule, which was adopted in 2007. The
Multi-Pollutant Rule is designed to reduce emissions of mercury, SO2, and NOx
state-wide by requiring the installation of specified control technologies at certain coal-fired
generating units by specific dates between December 31, 2008 and June 1, 2015. The State of
Georgia also adopted a companion rule that requires a 95% reduction in SO2 emissions
from the controlled units on the same or similar timetable. Through December 31, 2010, Georgia
Power had installed the required controls on 10 of its largest coal-fired generating units and is
in the process of installing the required controls on six additional units. As a result of
uncertainties related to the potential federal air quality regulations described above, Georgia
Power has suspended certain work related to both the installation of emissions control equipment at
Plant Branch Units 1 and 2 and Plant Yates Units 6 and 7 and the conversion of Plant Mitchell from
coal-fired to biomass-fired. Georgia Power continues to analyze the potential costs and benefits
of installing the required controls on its remaining coal-fired generating units in light of the
potential federal regulations described above. Georgia Power may determine that retiring and
replacing certain of these existing units with new generating resources or purchased power is more
economically efficient than installing the required environmental controls.
Georgia Power currently expects to file an update to its integrated resource plan in June 2011.
Under the terms of an Alternate Rate Plan approved by the Georgia PSC for Georgia Power which
became effective January 1, 2011 and will continue through December 31, 2013 (the 2010 ARP), any
costs associated with changes to Georgia Powers approved environmental operating or capital
budgets (resulting from new or revised environmental regulations) through 2013 that are approved by
the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be
recovered over a time period deemed appropriate by the Georgia PSC. Such costs that may be
deferred as a regulatory asset include any impairment losses that may result from a decision to
retire certain units that are no longer cost effective in light of new or modified environmental
regulations. In addition, in connection with the 2010 ARP, the Georgia PSC also approved revised
depreciation rates that will recover the remaining book value of certain of Georgia Powers
existing coal-fired units by December 31, 2014.
The ultimate outcome of these matters cannot be determined at this time.
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. In April 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 expected to propose revisions to the regulations in March 2011 and
issue final regulations in mid-2012. While the U.S. Supreme Courts decision
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
may ultimately result in greater flexibility for demonstrating compliance with the standards, the
full scope of the regulations will depend on the specific provisions of the EPAs final rule and on
the actual requirements established by state regulatory agencies and, therefore, cannot be
determined at this time. However, if the final rules require the installation of cooling towers at
certain existing facilities of the traditional operating companies, the traditional operating
companies may be subject to significant additional compliance costs and capital expenditures that
could affect future unit retirement and replacement decisions. Also, results of operations, cash
flows, and financial condition could be significantly impacted if such costs are not recovered
through regulated rates.
In December 2009, the EPA announced its determination that revision of the current effluent
guidelines for steam electric power plants is warranted, and the EPA has announced its intention to
adopt such revisions by January 2014. 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.
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 traditional operating companies currently operate 22 electric generating plants with on-site
coal combustion byproduct storage facilities (some with both wet (ash ponds) and dry (landfill)
storage facilities). In addition to on-site storage, the traditional operating companies also sell
a portion of their coal combustion byproducts to third parties for beneficial reuse (approximately
one-fourth in recent years). Historically, individual states have regulated coal combustion
byproducts and the states in Southern Companys service territory each have their own regulatory
parameters. Each traditional operating company has a routine and robust inspection program in
place to ensure the integrity of its coal ash surface impoundments and compliance with applicable
regulations.
The EPA is currently evaluating whether additional regulation of coal combustion byproducts
(including coal ash and gypsum) is merited under federal solid and hazardous waste laws. On June
21, 2010, the EPA published a proposed rule that requested comments on two potential regulatory
options for the management and disposal of coal combustion byproducts: regulation as a solid waste
or regulation as if the materials technically constituted a hazardous waste. Adoption of either
option could require closure of, or significant change to, existing storage facilities and
construction of lined landfills, as well as additional waste management and groundwater monitoring
requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal
combustion byproducts from regulation; however, a hazardous or other designation indicative of
heightened risk could limit or eliminate beneficial reuse options.
On November 19, 2010, Southern Company filed publicly available comments with the EPA regarding the
rulemaking proposal. These comments included a preliminary cost analysis under various
alternatives in the rulemaking proposal. Southern Company regards these estimates as pre-screening
figures that should be distinguished from the more formalized cost estimates Southern Company
provides for projects that are more definite as to the elements and timing of execution. Although
its analysis was preliminary, Southern Company concluded that potential compliance costs under the
proposed rules would be substantially higher than the estimates reflected in the EPAs rulemaking
proposal.
The ultimate financial and operational impact of any new regulations relating to coal combustion
byproducts cannot be determined at this time and will be dependent upon numerous factors. These
factors include: whether coal combustion byproducts will be regulated as hazardous waste or
non-hazardous waste; whether the EPA will require early closure of existing wet storage facilities;
whether beneficial reuse will be limited or eliminated through a hazardous waste designation;
whether the construction of lined landfills is required; whether hazardous waste landfill
permitting will be required for on-site storage; whether additional waste water treatment will be
required; the extent of any additional groundwater monitoring requirements; whether any equipment
modifications will be required; the extent of any changes to site safety practices under a
hazardous waste designation; and the time period over which compliance will be required. There can
be no assurance as to the timing of adoption or the ultimate form of any such rules.
II-26
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
While the ultimate outcome of this matter cannot be determined at this time, and will depend on the
final form of any rules adopted and the outcome of any legal challenges, additional regulation of
coal combustion byproducts could have a material impact on the generation, management, beneficial
use, and disposal of such byproducts. Any material changes are likely to result in substantial
additional compliance, operational, and capital costs that could affect future unit retirement and
replacement decisions. Moreover, the traditional operating companies could incur additional
material asset retirement obligations with respect to closing existing storage facilities.
Southern Companys results of operations, cash flows, and financial condition could be
significantly impacted 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.
Global Climate Issues
Although the U.S. House of Representatives passed the American Clean Energy and Security Act of
2009, with the goal of mandating renewable energy standards and reductions in greenhouse gas
emissions, neither this legislation nor similar measures passed the U.S. Senate before the end of
the 2010 session. Federal legislative proposals that would impose mandatory requirements related
to greenhouse gas emissions, renewable energy standards, and/or energy efficiency standards are
expected to continue to be considered in Congress.
The financial and operational impacts of climate or energy 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, natural gas, and biomass prices and
cost recovery through regulated rates.
While climate legislation has yet to be adopted, the EPA is moving forward with regulation of
greenhouse gases under the Clean Air Act. 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.
In December 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 April 1, 2010, the EPA issued a final rule regulating greenhouse
gas emissions from new motor vehicles under the Clean Air Act. The EPA has taken the position that
when this rule became effective on January 2, 2011, carbon dioxide and other greenhouse gases
became 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 and other
commercial and industrial facilities. 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. On May 13, 2010, the EPA issued a final rule, known as the Tailoring Rule, governing how
these programs would be applied to stationary sources, including power plants. This rule
establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions
sources. The first phase, which began on January 2, 2011, applies to sources and projects that
would already be covered under PSD or Title V, whereas the second phase will begin on July 1, 2011
and applies to sources and projects that would not otherwise trigger those programs but for their
greenhouse gas emissions. In addition to these rules, the EPA has entered into a proposed
settlement agreement to issue standards of performance for greenhouse gas emissions from new and
modified fossil fuel-fired electric generating units and greenhouse gas emissions guidelines for
existing sources. Under the proposed settlement agreement, the EPA commits to issue the proposed
standards by July 2011 and the final standards by May 2012.
All of the EPAs final Clean Air Act rulemakings have been challenged in the U.S. Court of Appeals
for the District of Columbia Circuit; however, the court declined motions to stay the rules pending
resolution of those challenges. As a result, the rules may impact the amount of time it takes to
obtain PSD permits for new generation and major modifications to existing generating units and the
requirements ultimately imposed by those permits. The ultimate outcome of these rules cannot be
determined at this time and will depend on the content of the final rules and the outcome of any
legal challenges.
International climate change negotiations under the United Nations Framework Convention on Climate
Change also continue. The December 2009 negotiations resulted in a nonbinding agreement that
included a pledge from both developed and developing countries to reduce their greenhouse gas
emissions. The most recent round of negotiations took place in December 2010. The outcome and
impact of the international negotiations cannot be determined at this time.
Although the outcome of federal, state, and 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
II-27
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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 2009, the total carbon dioxide emissions from the fossil fuel-fired electric generating units
owned by the electric utilities were approximately 121 million metric tons. The preliminary
estimate of carbon dioxide emissions from these units in 2010 is approximately 131 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, but are not limited to, new nuclear generation, including
two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4) in Georgia;
construction of the Kemper IGCC in Mississippi with 65% carbon capture; and renewables investments,
including the construction of a biomass plant in Sacul, Texas. In addition, a subsidiary of the
Company completed construction on a solar photovoltaic plant near Cimarron, New Mexico in 2010.
The Company is currently considering additional projects and is pursuing research into the costs
and viability of other renewable technologies.
PSC Matters
Alabama Power
Rate RSE
Alabama Power operates under Rate RSE approved by the Alabama PSC. Alabama Powers Rate RSE
adjustments are based on forward-looking information for the applicable upcoming calendar year.
Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual
adjustment is limited to 5.0%. Retail rates remain unchanged when the retail return on common
equity (ROE) is projected to be between 13.0% and 14.5%. If Alabama Powers actual retail return
on common equity is above the allowed equity return range, customer refunds will be required;
however, there is no provision for additional customer billings should the actual retail ROE fall
below the allowed equity return range.
The Rate RSE increase for 2010 was 3.24%, or $152 million annually, and was effective in January
2010. In December 2010, Alabama Power made its Rate RSE submission to the Alabama PSC of projected
data for calendar year 2011 and earnings were within the specified return range. Consequently, the
retail rates will remain unchanged in 2011 under Rate RSE. Under the terms of Rate RSE, the
maximum increase for 2012 cannot exceed 5.00%.
Rate CNP
Alabama Powers retail rates, approved by the Alabama PSC, provide for adjustments to recognize the
placing of new generating facilities into retail service and the recovery of retail costs
associated with certificated PPAs under a Rate CNP. There was no adjustment to the Rate CNP to
recover certificated PPA costs in 2008 or 2009. Effective April 2010, Rate CNP was reduced by
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. It is estimated that there will be a
slight decrease to the current Rate CNP effective April 2011.
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 certain invested capital. Retail rates increased approximately 2.4%
in January 2008 and 4.3% in January 2010 due to environmental costs. In October 2008, Alabama
Power agreed to defer collection of any increase in rates under this portion of Rate CNP, which
permits recovery of costs associated with environmental laws and regulations, from 2009 until 2010.
The deferral of the retail rate adjustments had an immaterial impact on annual cash flows, and had
no significant effect on the Companys revenues or net income. On December 1, 2010, Alabama Power
submitted calculations associated with its cost of complying with environmental mandates, as
provided under Rate CNP Environmental. The filing reflects an incremental increase in the revenue
requirement associated with such environmental compliance, which would be recoverable in the
billing months of January 2011 through December 2011. In order to afford additional rate stability
to customers as the economy continues to recover from the recession, the Alabama PSC ordered on
January 4, 2011 that Alabama Power leave in effect for 2011 the factors associated with Alabama
Powers
II-28
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
environmental compliance costs for the year 2010. Any recoverable amounts associated with 2011
will be reflected in the 2012 filing. The ultimate outcome of this matter cannot be determined at
this time.
Natural Disaster Reserve
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and
maintenance expenses to cover the cost of damages from major storms to its transmission and
distribution facilities. The order approves a separate monthly Natural Disaster Rate
(Rate NDR) charge to customers consisting of two components. The first component is intended to
establish and maintain a reserve balance for future storms and is an on-going part of customer
billing. The second component of the Rate NDR charge is intended to allow recovery of any existing
deferred storm-related operations and maintenance costs and any future reserve deficits over a
24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance
in the NDR when costs of storm damage exceed any established reserve balance. Alabama Power has
discretionary authority to accrue certain additional amounts as circumstances warrant.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance
expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not
have an effect on net income but will impact operating cash flows.
On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75
million authorized limit and allows Alabama Power to make additional accruals to the NDR. The
order also allows for reliability-related expenditures to be charged against the additional
accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the
NDR to reliability-related expenditures as a part of an annual budget process for the following
year or during the current year for identified unbudgeted reliability-related expenditures that are
incurred. Accruals that have not been designated can be used to offset storm charges. Additional
accruals to the NDR will enhance Alabama Powers ability to deal with the financial effects of
future natural disasters, promote system reliability, and offset costs retail customers would
otherwise bear. The structure of the monthly Rate NDR charge to customers is not altered and
continues to include a component to maintain the reserve.
For the year ended December 31, 2010, Alabama Power accrued an additional $48 million to the NDR,
resulting in an accumulated balance of approximately $127 million. For the year ended December 31,
2009, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated
balance of approximately $75 million. These accruals are included in the balance sheets under
other regulatory liabilities, deferred and are reflected as operations and maintenance expense in
the statements of income.
Nuclear Outage Accounting Order
On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting
process associated with routine refueling activities. Previously, Alabama Power accrued nuclear
outage operations and maintenance expenses for the two units of Plant Farley during the 18-month
cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred
when the charges actually occur and then amortized over the subsequent 18-month period.
The initial result of implementation of the new accounting order is that no nuclear maintenance
outage expenses will be recognized from January 2011 through December 2011, which will decrease
nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million.
During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley
will be deferred to a regulatory asset account; beginning in January 2012, these deferred costs
will be amortized to nuclear operations and maintenance expenses over an 18-month period. During
the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley
will be deferred to a regulatory asset account; beginning in July 2012, these deferred costs will
be amortized to nuclear operations and maintenance expenses over an 18-month period. Alabama Power
will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of
expenses over a subsequent 18-month period.
Georgia Power
The economic recession significantly reduced Georgia Powers revenues upon which retail rates were
set by the Georgia PSC for 2008 through 2010 (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, in June 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.
In August 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting
order, Georgia Power could amortize up to $108 million of the regulatory liability in 2009 and up
to $216 million in 2010, limited to the amount needed to earn no
II-29
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
more than a 9.75% and 10.15% retail ROE in 2009 and 2010, respectively. For the years ended
December 31, 2009 and 2010, Georgia Power amortized $41 million and $174 million of the regulatory
liability, respectively.
On December 21, 2010, the Georgia PSC approved the 2010 ARP. The terms of the 2010 ARP reflect a
settlement agreement among Georgia Power, the Georgia PSCs Public Interest Advocacy Staff, and
eight other intervenors. Under the terms of the 2010 ARP, Georgia Power will amortize
approximately $92 million of its remaining regulatory liability related to other cost of removal
obligations over the three years ending December 31, 2013.
Also under the terms of the 2010 ARP, effective January 1, 2011, Georgia Power increased its (1)
traditional base tariff rates by approximately $347 million; (2) Demand-Side Management (DSM)
tariff rates by approximately $31 million; (3) ECCR tariff rate by approximately $168 million; and
(4) Municipal Franchise Fee (MFF) tariff rate by approximately $16 million, for a total increase in
base revenues of approximately $562 million.
Under the 2010 ARP, the following additional base rate adjustments will be made to Georgia Powers
tariffs in 2012 and 2013:
|
|
Effective January 1, 2012, the DSM tariffs will increase by $17 million; |
|
|
|
Effective April 1, 2012, the traditional base tariffs will increase to
recover the revenue requirements for the lesser of actual capital costs
incurred or the amounts certified by the Georgia PSC for Plant McDonough Units
4 and 5 for the period from commercial operation through December 31, 2013; |
|
|
|
Effective January 1, 2013, the DSM tariffs will increase by $18 million; |
|
|
|
Effective January 1, 2013, the traditional base tariffs will increase
to recover the revenue requirements for the lesser of actual capital costs
incurred or the amounts certified by the Georgia PSC for Plant McDonough Unit 6
for the period from commercial operation through December 31, 2013; and |
|
|
|
The MFF tariff will increase consistent with these adjustments. |
Georgia Power currently estimates these adjustments will result in annualized base revenue
increases of approximately $190 million in 2012 and $93 million in 2013.
Under the 2010 ARP, Georgia Powers retail ROE is set at 11.15% and earnings will be evaluated
against a retail ROE range of 10.25% to 12.25%. Two-thirds of any earnings above 12.25% will be
directly refunded to customers, with the remaining one-third retained by Georgia Power. If at any
time during the term of the 2010 ARP, Georgia Power projects that retail earnings will be below
10.25% for any calendar year, it may petition the Georgia PSC for the implementation of an Interim
Cost Recovery (ICR) tariff to adjust Georgia Powers earnings back to a 10.25% retail ROE. The
Georgia PSC will have 90 days to rule on any such request. If approved, any ICR tariff would
expire at the earlier of January 1, 2014 or the end of the calendar year in which the ICR tariff
becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC
chooses not to implement the ICR, Georgia Power may file a full rate case.
Except as provided above, Georgia Power will not file for a general base rate increase while the
2010 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2013, in
response to which the Georgia PSC would be expected to determine whether the 2010 ARP should be
continued, modified, or discontinued.
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 Alabama Power,
Georgia Power, and Gulf Power of approximately $420 million at December 31, 2010. As of December
31, 2010, Mississippi Power had a total over recovered fuel balance of $55 million. At December
31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf
Power were approximately $667 million and Alabama Power and Mississippi Power had a total over
recovered fuel balance of approximately $229 million. The traditional operating companies
continuously monitor the under or over recovered fuel cost balances.
II-30
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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
Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the U.S.
Department of Energy (DOE), formally accepting a $165 million grant under the American Recovery and
Reinvestment Act of 2009. This funding, to be matched by Southern Company, will be used for
transmission and distribution automation and modernization projects that must be completed by April
28, 2013. The ultimate outcome of this matter cannot be determined at this time.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and,
on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (together with PPACA,
the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law.
The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree
health benefit plans that provide prescription drug benefits that are at least actuarially
equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid
to employers was introduced as part of the Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company and the traditional
operating companies have been receiving the federal subsidy related to certain retiree prescription
drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare
Part D. Under the MPDIMA, the federal subsidy does not reduce an employers income tax deduction
for the costs of providing such prescription drug plans nor is it subject to income tax
individually. Under the Acts, beginning in 2013, an employers income tax deduction for the costs
of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by
the amount of the federal subsidy. Under generally accepted accounting principles (GAAP), any
impact from a change in tax law must be recognized in the period enacted regardless of the
effective date; however, as a result of state regulatory treatment, this change had no material
impact on the financial statements of Southern Company. Southern Company continues to assess the
extent to which the legislation and associated regulations may affect its future healthcare and related
employee benefit plan costs. Any future impact on the financial statements of Southern Company
cannot be determined at this time. See Note 5 to the financial statements under Current and
Deferred Income Taxes for additional information.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Powers 2005 through 2009 income tax filings for the State of Georgia include state income
tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims
for the years 2002 through 2004. The Georgia Department of Revenue (DOR) 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. On March 22, 2010, the Superior
Court of Fulton County ruled in favor of Georgia Powers motion for summary judgment. The Georgia
DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any
decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax
benefit has been recorded related to these credits. If Georgia Power prevails, no material impact
on Southern Companys net income is expected as a significant portion of any tax benefit is
expected to be returned to retail customers in accordance with the 2010 ARP. 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. See Note 5 to the financial statements under
Unrecognized Tax Benefits for additional information. The ultimate outcome of this matter cannot
now be determined.
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with
Southern Companys generation, transmission, and distribution systems with the filing of the 2009
federal income tax return in September 2010. On a consolidated basis, the new tax method resulted
in net positive cash flow in 2010 of approximately $297 million. Although Internal Revenue Service
(IRS) approval of this change is considered automatic, the amount claimed is subject to review
because the IRS will be issuing
II-31
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
final guidance on this matter. Currently, the IRS is working with the utility industry in an
effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty
concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded
for the change in the tax accounting method for repair costs. See Note 5 to the financial
statements under Unrecognized Tax Benefits for additional information. The ultimate outcome of
this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law.
The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and
placed in service in 2010 (and for certain long-term construction projects to be placed in service
in 2011). Additionally, on December 17, 2010, the Tax Relief, Unemployment Insurance
Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives
in the Tax Relief Act include 100% bonus depreciation for property placed in service after
September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in
service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain
long-term construction projects to be placed in service in 2013), which could have a significant
impact on the future cash flows of Southern Company. The application of the bonus depreciation
provisions in these acts in 2010 provided approximately $393 million in increased cash flow.
Southern Company estimates the potential increased cash flow for 2011 to be between approximately $500 million
and $600 million.
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 of 1986, as
amended. The deduction is equal to a stated percentage of qualified production activities net
income. The percentage was phased in over the years 2005 through 2010. For 2008 and 2009, a 6%
reduction was available to Southern Company. Thereafter, the allowed rate is 9%; however, due to
increased tax deductions from bonus depreciation and pension contributions, there was no domestic
production deduction available to Southern Company for 2010, and none is projected to be available
for 2011. 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 natural gas and biomass units at Southern Power, natural gas and new nuclear units at
Georgia Power, and the Kemper IGCC at Mississippi Power, 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, Retail Regulatory Matters
Georgia Power Other Construction, and Retail Regulatory Matters Mississippi Power Integrated Coal
Gasification Combined Cycle for additional information.
On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost
Recovery (NCCR) tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act.
The Georgia PSC has ordered Georgia Power to report against the total certified cost of Plant
Vogtle Units 3 and 4 of approximately $6.1 billion. In addition, on December 21, 2010, the Georgia
PSC approved Georgia Powers NCCR tariff. The NCCR tariff became effective January 1, 2011 and is
expected to collect approximately $223 million during 2011 to recover financing costs associated
with the construction of Plant Vogtle Units 3 and 4.
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 U.S. In particular, personal injury and other claims for
damages caused by alleged exposure to hazardous materials,
II-32
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP.
Significant accounting policies are described in Note 1 to the financial statements. In the
application of these policies, certain estimates are made that may have a material impact on
Southern Companys results of operations and related disclosures. Different assumptions and
measurements could produce estimates that are significantly different from those recorded in the
financial statements. Senior management has reviewed and discussed the following critical
accounting policies and estimates with the Audit Committee of Southern Companys Board of
Directors.
Electric Utility Regulation
Southern Companys traditional operating companies, which comprised approximately 95% of Southern
Companys total operating revenues for 2010, 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 GAAP. However, adverse legislative,
judicial, or regulatory actions could materially impact the amounts of such regulatory assets and
liabilities and could adversely impact the Companys financial statements.
Contingent Obligations
Southern Company 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.
II-33
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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. |
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.
Alabama Power is better able to determine unbilled KWH sales due to the installation of automated
meters. At the end of each month, amounts of electricity delivered are read for the customers with
automated meters. From this reading, unbilled KWH sales are determined and included in Alabama
Powers unbilled revenue calculation. For customers without automated meter readings, amounts of
unbilled electricity delivered are estimated.
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
consider external actuarial advice. Southern Company determines the long-term return on plan
assets by applying the long-term rate of expected returns on various asset classes to Southern
Companys target asset allocation. Southern Company discounts the future cash flows related to its
postretirement benefit plans using a single-point discount rate developed from the weighted average
of market-observed yields for high quality fixed income securities with maturities that correspond
to expected benefit payments.
II-34
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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 2011 |
|
at December 31, 2010 |
|
at December 31, 2010 |
|
|
(in millions) |
25 basis point change in
discount rate |
|
$25/$(17) |
|
$249/$(236) |
|
$52/$(50) |
25 basis point change in
salary assumption |
|
$13/$(12) |
|
$63/$(60) |
|
N/M |
25 basis point change in
long-term return on plan assets |
|
$20/$(20) |
|
N/M |
|
N/M |
|
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Companys financial condition remained stable at December 31, 2010. Southern Company
intends to continue to monitor its access to short-term and long-term capital markets as well as
its bank credit arrangements to meet future capital and liquidity needs. See Sources of Capital
and Financing Activities herein for additional information.
Southern Companys investments in the qualified pension plan and the nuclear decommissioning trust
funds remained stable in value as of December 31, 2010. In December 2010, the traditional
operating companies and certain other subsidiaries contributed $620 million to the qualified
pension plan. Southern Company does not expect any material changes to funding obligations to the
nuclear decommissioning trust funds prior to 2014.
Net cash provided from operating activities in 2010 totaled $4 billion, an increase of $728 million
from the corresponding period in 2009. Significant changes in operating cash flow for 2010 as
compared to the corresponding period in 2009 include an increase in net income, a reduction in
fossil fuel stock, and an increase in deferred income taxes primarily due to the change in the tax
accounting method for repair costs. A contribution to the qualified pension plan partially offset
these increases. 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, 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 used for investing activities in 2010 totaled $4.3 billion primarily due to property
additions to utility plant. 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.
Net cash provided from financing activities totaled $22 million in 2010, a decrease of $1.3 billion
from the corresponding period in 2009. This decrease was primarily due to redemptions of long-term
debt in 2010. Net cash provided from financing activities totaled $1.3 billion in 2009 primarily
due to the issuances of new long-term debt and common stock, 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.
Significant balance sheet changes in 2010 include an increase of $2.8 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
II-35
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
significant changes include an increase in notes payable of $658 million used primarily for
construction expenditures and general corporate purposes and $1.3 billion of additional equity.
At the end of 2010, the closing price of Southern Companys common stock was $38.23 per share,
compared with book value of $19.21 per share. The market-to-book value ratio was 199% at the end
of 2010, compared with 184% at year-end 2009.
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 2011, as well as in subsequent years, will be contingent on Southern Companys
investment opportunities.
Except as described below with respect to potential DOE loan guarantees, 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 amount, type, and timing of any future financings, if needed, will depend
upon prevailing market conditions, regulatory approval, and other factors.
On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional
commitment for federal loan guarantees that would apply to future Georgia Power borrowings related
to 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 the lesser of
70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the
Federal Financing Bank. 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.
In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a
portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced
due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and
conditions of any loan guarantee. There can be no assurance that the DOE will issue federal loan
guarantees for Mississippi 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, 2010, Southern Company and its subsidiaries had approximately $447.4 million of
cash and cash equivalents and $4.8 billion of unused credit arrangements with banks, of which $1.6
billion expire in 2011 and $3.2 billion expire in 2012. Approximately $81 million of the credit
facilities expiring in 2011 allow for the execution of term loans for an additional two-year
period, and $927 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
II-36
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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, 2010 was approximately $1.3 billion. See Note 6 to
the financial statements under Bank Credit Arrangements for additional information. The
traditional operating companies may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for the benefit of each
of the traditional operating companies. At December 31, 2010, the Southern Company system had
approximately $1.3 billion of commercial paper borrowings outstanding with a weighted average
interest rate of 0.3% per annum. During 2010, Southern Company had an average of $690 million of
commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum
amount outstanding was $1.3 billion. At December 31, 2009, the Southern Company system had
approximately $638 million of commercial paper borrowings outstanding with a weighted average
interest rate of 0.3% per annum. During 2009, Southern Company had an average of $956 million of
commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum
amount outstanding for commercial paper was $1.4 billion. Management believes that the need for
working capital can be adequately met by utilizing commercial paper programs, lines of credit, and
cash.
Financing Activities
During 2010, Southern Company issued $400 million aggregate principal amount of Series 2010A 2.375%
Senior Notes due September 15, 2015. The net proceeds were used to redeem $250 million aggregate
principal amount of Southern Company Capital Funding, Inc.s Series C 5.75% Senior Notes due
November 15, 2015. In addition, certain Southern Company subsidiaries issued $2.8 billion of
senior notes and other long-term debt and entered into bank term loan agreements of $125 million.
The proceeds were used to repay maturing long-term and short-term indebtedness and for other
general corporate purposes, including the applicable subsidiarys continuous construction program.
Southern Company also issued 19.6 million shares of common stock for $629 million through the
Southern Investment Plan and employee and director stock plans. In addition, Southern Company
issued 4.1 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 $143 million, net of $1 million in fees and commissions. The proceeds from the sale of
the common stock were used by the Company for general corporate purposes, including the investment
by the Company in its subsidiaries, and to repay a portion of its outstanding short-term
indebtedness.
In December 2010, Mississippi Power incurred obligations in connection with the issuance of $100
million of revenue bonds in two series, each of which is due December 1, 2040. The first series of
$50 million was issued with an initial fixed rate of 2.25% through January 14, 2013 and the second
series of $50 million was issued with a floating rate. The proceeds from the first series bonds
were used to finance the acquisition and construction of buildings and immovable equipment in
connection with Mississippi Powers construction of the Kemper IGCC. Proceeds from the second
series bonds were classified as restricted cash at December 31, 2010 and these bonds were redeemed
on February 8, 2011.
Subsequent to December 31, 2010, Alabama Power entered into forward-starting interest rate swaps to
mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional
amount of the swaps totaled $200 million.
Also subsequent to December 31, 2010, Georgia Power issued $300 million aggregate principal amount
of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay a
portion of Georgia Powers outstanding short-term indebtedness and for general corporate purposes,
including Georgia Powers continuous construction program.
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, Mississippi Power was required to notify the lessor, Juniper, if it
intended to terminate the lease at the end
II-37
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
of the initial term expiring in October 2011. Mississippi Power chose not to give notice to
terminate the lease. Mississippi Power has the option to purchase the Plant Daniel combined cycle
generating units for approximately $354 million or renew the lease for approximately $31 million
annually for 10 years. Mississippi Power will have to provide notice of its intent to either renew
the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be
determined at this time. 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.
At December 31, 2010, 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
$489 million. At December 31, 2010, the maximum potential collateral requirements under these
contracts at a rating below BBB- and/or Baa3 were approximately $2.5 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.
On August 12, 2010, Moodys Investors Service (Moodys) downgraded the issuer and long-term debt
ratings of Southern Company (senior unsecured to Baa1 from A3); Moodys also announced that it had
downgraded the short-term ratings of Southern Company and a financing subsidiary of Southern
Company that issues commercial paper for the benefit of several Southern Company subsidiaries
(including Georgia Power, Gulf Power, and Mississippi Power) to P-2 from P-1. In addition, Moodys
downgraded the issuer and long-term debt ratings of Georgia Power (senior unsecured to A3 from A2),
Gulf Power (senior unsecured to A3 from A2), and Mississippi Power (senior unsecured to A2 from
A1). All of these companies have stable ratings outlooks from Moodys.
On September 3, 2010, Fitch Ratings, Inc. (Fitch) confirmed the long-term debt ratings of Southern
Company (senior unsecured A), but announced that the ratings outlook of Southern Company had been
revised to negative, and that the issuer default ratings and long-term debt ratings of Mississippi
Power had been downgraded by one notch (senior unsecured to A+ from AA- and issuer default rating
to A from A+). On December 22, 2010, Fitch announced that the ratings outlook of Southern Company
and Georgia Power had been revised from negative to stable.
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk.
The Company may also occasionally have limited exposure to foreign currency exchange rates. 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, Southern Company and certain of its
subsidiaries enter into derivatives that have been designated as hedges. Derivatives outstanding
at December 31, 2010 have a notional amount of $650 million and are related to fixed and floating
rate obligations over the next several years. The weighted average interest rate on $2.5 billion
of long-term variable interest rate exposure that has not been hedged at January 1, 2011 was 0.75%.
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 $25
million at January 1, 2011. 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 and other various cost recovery mechanisms, the traditional
operating companies continue to have limited exposure to market volatility in interest rates,
foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Powers
exposure to market volatility in commodity fuel prices and prices of electricity is limited because
its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser.
However, Southern Power has been and may continue to be exposed to market volatility in
energy-related commodity prices as a result of 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
II-38
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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, the majority of which are
composed of regulatory hedges, for the years ended December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
Changes |
|
Changes |
|
|
Fair Value |
|
|
(in millions) |
Contracts outstanding at the beginning of the period, assets
(liabilities), net |
|
$ |
(178 |
) |
|
$ |
(285 |
) |
Contracts realized or settled |
|
|
197 |
|
|
|
367 |
|
Current period changes(a) |
|
|
(215 |
) |
|
|
(260 |
) |
|
Contracts outstanding at the end of the period, assets (liabilities), net |
|
$ |
(196 |
) |
|
$ |
(178 |
) |
|
|
|
|
(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, 2010 was a decrease of $18 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 the price of natural gas. At December 31, 2010, Southern Company had a net hedge
volume of 149 million mmBtu with a weighted average contract cost approximately $1.35 per mmBtu
above market prices, compared to 145 million mmBtu at December 31, 2009 with a weighted average
contract cost approximately $1.23 per mmBtu above market prices. The majority of the natural gas
hedges are recovered through the traditional operating companies fuel cost recovery clauses.
At December 31, the net fair value of energy-related derivative contracts by hedge designation was
reflected in the financial statements as assets (liabilities) were as follows:
|
|
|
|
|
|
|
|
|
Asset (Liability) Derivatives |
|
2010 |
|
2009 |
|
|
(in millions) |
Regulatory hedges |
|
$ |
(193 |
) |
|
$ |
(175 |
) |
Cash flow hedges |
|
|
(1 |
) |
|
|
(2 |
) |
Not designated |
|
|
(2 |
) |
|
|
(1 |
) |
|
Total fair value |
|
$ |
(196 |
) |
|
$ |
(178 |
) |
|
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 that are 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, 2010, 2009, and 2008 for energy-related derivative contracts that are not hedges
were $(2) million, $(5) million, and $1 million, respectively.
II-39
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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 of fair value measurement. The maturities of the energy-related
derivative contracts and the level of the fair value hierarchy in which they fall at December 31,
2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
Fair Value Measurements |
|
|
Total |
|
Maturity |
|
|
Fair Value |
|
Year 1 |
|
Years 2&3 |
|
Years 4&5 |
|
|
(in millions) |
Level 1 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Level 2 |
|
|
(196 |
) |
|
|
(144 |
) |
|
|
(52 |
) |
|
|
|
|
Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at end of period |
|
$ |
(196 |
) |
|
$ |
(144 |
) |
|
$ |
(52 |
) |
|
$ |
|
|
|
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 Standard & Poors, a division of The McGraw Hill Companies, Inc., 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.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010
could impact the use of over-the-counter derivatives by the Company. Regulations to implement the
Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives,
such as margin and reporting requirements, which could affect both the use and cost of
over-the-counter derivatives. The impact, if any, cannot be determined until regulations are
finalized.
Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and
international and the creditworthiness of the lessees, including a review of the value of the
underlying leased assets and the credit ratings of the lessees. Southern Companys domestic lease
transactions generally do not have any credit enhancement mechanisms; however, the lessees in its
international lease transactions have pledged various deposits as additional security to secure the
obligations. The lessees in the Companys international lease transactions are also required to
provide additional collateral in the event of a credit downgrade below a certain level.
Capital Requirements and Contractual Obligations
The construction programs of the Companys subsidiaries are currently estimated to include a base
level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013,
respectively. Included in these estimated amounts are environmental expenditures to comply with
existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012,
and 2013, respectively. In addition, the Company currently estimates that potential incremental
investments to comply with anticipated new environmental regulations could range from $74 million
to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion
for 2013. 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 generating plants, including unit retirements and
replacements, 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; storm impacts; 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, Retail Regulatory Matters Georgia Power Other Construction, and Retail
Regulatory Matters Mississippi Power 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.
II-40
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
In addition, as discussed in Note 2 to the financial statements, Southern Company provides
postretirement benefits to substantially all employees and funds trusts to the extent required by
the traditional operating companies respective regulatory commissions.
Other funding requirements related to obligations associated with scheduled maturities of long-term
debt, as well as the related interest, derivative obligations, preferred and preference stock
dividends, leases, and other purchase commitments are detailed in the contractual obligations table
that follows. See Notes 1, 6, 7, and 11 to the financial statements for additional information.
II-41
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012- |
|
2014- |
|
After |
|
Uncertain |
|
|
|
|
2011 |
|
2013 |
|
2015 |
|
2015 |
|
Timing(d) |
|
Total |
|
|
(in millions) |
Long-term debt(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
1,278 |
|
|
$ |
2,938 |
|
|
$ |
1,138 |
|
|
$ |
14,029 |
|
|
$ |
|
|
|
$ |
19,383 |
|
Interest |
|
|
876 |
|
|
|
1,610 |
|
|
|
1,369 |
|
|
|
11,194 |
|
|
|
|
|
|
|
15,049 |
|
Preferred and preference stock dividends(b) |
|
|
65 |
|
|
|
130 |
|
|
|
130 |
|
|
|
|
|
|
|
|
|
|
|
325 |
|
Energy-related derivative obligations(c) |
|
|
151 |
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
206 |
|
Operating leases |
|
|
154 |
|
|
|
170 |
|
|
|
94 |
|
|
|
103 |
|
|
|
|
|
|
|
521 |
|
Capital leases |
|
|
23 |
|
|
|
28 |
|
|
|
13 |
|
|
|
35 |
|
|
|
|
|
|
|
99 |
|
Unrecognized tax benefits and interest(d) |
|
|
203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122 |
|
|
|
325 |
|
Purchase commitments(e) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital(f) |
|
|
4,554 |
|
|
|
9,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,796 |
|
Limestone(g) |
|
|
39 |
|
|
|
82 |
|
|
|
72 |
|
|
|
89 |
|
|
|
|
|
|
|
282 |
|
Coal |
|
|
3,810 |
|
|
|
3,244 |
|
|
|
1,656 |
|
|
|
1,798 |
|
|
|
|
|
|
|
10,508 |
|
Nuclear fuel |
|
|
335 |
|
|
|
427 |
|
|
|
349 |
|
|
|
807 |
|
|
|
|
|
|
|
1,918 |
|
Natural gas(h) |
|
|
1,357 |
|
|
|
2,280 |
|
|
|
1,687 |
|
|
|
3,413 |
|
|
|
|
|
|
|
8,737 |
|
Biomass fuel(i) |
|
|
|
|
|
|
32 |
|
|
|
36 |
|
|
|
110 |
|
|
|
|
|
|
|
178 |
|
Purchased power |
|
|
260 |
|
|
|
506 |
|
|
|
559 |
|
|
|
2,439 |
|
|
|
|
|
|
|
3,764 |
|
Long-term service agreements(j) |
|
|
110 |
|
|
|
270 |
|
|
|
290 |
|
|
|
1,435 |
|
|
|
|
|
|
|
2,105 |
|
Trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning(k) |
|
|
3 |
|
|
|
4 |
|
|
|
4 |
|
|
|
35 |
|
|
|
|
|
|
|
46 |
|
Pension and other postretirement benefit plans(l) |
|
|
64 |
|
|
|
147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211 |
|
|
Total |
|
$ |
13,282 |
|
|
$ |
21,165 |
|
|
$ |
7,397 |
|
|
$ |
35,487 |
|
|
$ |
122 |
|
|
$ |
77,453 |
|
|
|
|
|
(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, 2011, as reflected in the statements of
capitalization. Fixed rates include, where applicable, the effects of interest rate
derivatives employed to manage interest rate risk. Long-term debt excludes capital lease
amounts (shown separately). |
|
(b) |
|
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 $122 million in unrecognized tax benefits and
corresponding 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
2010, 2009, and 2008 were $4.0 billion, $3.5 billion, and $3.8 billion, respectively. |
|
(f) |
|
Southern Company provides forecasted capital expenditures for a three-year period. Amounts
represent current estimates of total expenditures, excluding those amounts related to
contractual purchase commitments for nuclear fuel. In addition, such amounts exclude Southern
Companys estimates of potential incremental investments to comply with anticipated new environmental
regulations which could range from $74 million to $289 million for 2011, $191 million to $670
million for 2012, and $476 million to $1.9 billion for 2013. At December 31, 2010,
significant purchase commitments were outstanding in connection with the construction program. |
|
(g) |
|
As part of Southern Companys program to reduce SO2 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, 2010. |
|
(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 fund contributions are based on the 2010 ARP for
Georgia Power. |
|
(l) |
|
Southern Company forecasts contributions to the qualified pension and other postretirement
benefit plans over a three-year period. Southern Company does not expect to be required to make
any contributions to the qualified pension plan during the next three years. See Note 2 to the
financial statements for additional information related to the pension and other postretirement
benefit plans, including estimated benefit payments. Certain benefit payments will be made through
the related benefit plans. Other benefit payments will be made from Southern Companys corporate
assets. |
II-42
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Companys 2010 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, economic recovery, fuel cost
recovery and other rate actions, environmental regulations and expenditures, future earnings,
dividend payout ratios, access to sources of capital, projections for the qualified pension plan,
postretirement benefit, and nuclear decommissioning trust fund contributions, financing activities,
start and completion of construction projects, plans and estimated costs for new generation
resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent
healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax
Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, 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 changes, 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, coal combustion byproducts, and emissions of sulfur,
nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and
other substances, financial reform legislation, 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, and IRS audits; |
|
|
|
the effects, extent, and timing of the entry of additional competition in the markets in
which Southern Companys subsidiaries operate; |
|
|
|
variations in demand for electricity, including those relating to weather, the general
economy and recovery from the 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 trust funds; |
|
|
|
advances in technology; |
|
|
|
state and federal rate regulations and the impact of pending and future rate cases and
negotiations, including rate actions relating to fuel and other cost recovery mechanisms; |
|
|
|
regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia
PSC and NRC approvals and potential DOE loan guarantees; |
|
|
|
regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC
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.
II-43
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Retail revenues |
|
$ |
14,791 |
|
|
$ |
13,307 |
|
|
$ |
14,055 |
|
Wholesale revenues |
|
|
1,994 |
|
|
|
1,802 |
|
|
|
2,400 |
|
Other electric revenues |
|
|
589 |
|
|
|
533 |
|
|
|
545 |
|
Other revenues |
|
|
82 |
|
|
|
101 |
|
|
|
127 |
|
|
Total operating revenues |
|
|
17,456 |
|
|
|
15,743 |
|
|
|
17,127 |
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Fuel |
|
|
6,699 |
|
|
|
5,952 |
|
|
|
6,818 |
|
Purchased power |
|
|
563 |
|
|
|
474 |
|
|
|
815 |
|
Other operations and maintenance |
|
|
4,010 |
|
|
|
3,526 |
|
|
|
3,748 |
|
MC Asset Recovery litigation settlement |
|
|
|
|
|
|
202 |
|
|
|
|
|
Depreciation and amortization |
|
|
1,513 |
|
|
|
1,503 |
|
|
|
1,443 |
|
Taxes other than income taxes |
|
|
869 |
|
|
|
818 |
|
|
|
797 |
|
|
Total operating expenses |
|
|
13,654 |
|
|
|
12,475 |
|
|
|
13,621 |
|
|
Operating Income |
|
|
3,802 |
|
|
|
3,268 |
|
|
|
3,506 |
|
Other Income and (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction |
|
|
194 |
|
|
|
200 |
|
|
|
152 |
|
Interest income |
|
|
24 |
|
|
|
23 |
|
|
|
33 |
|
Leveraged lease income (losses) |
|
|
18 |
|
|
|
31 |
|
|
|
(85 |
) |
Gain on disposition of lease termination |
|
|
|
|
|
|
26 |
|
|
|
|
|
Loss on extinguishment of debt |
|
|
|
|
|
|
(17 |
) |
|
|
|
|
Interest expense, net of amounts capitalized |
|
|
(895 |
) |
|
|
(905 |
) |
|
|
(866 |
) |
Other income (expense), net |
|
|
(77 |
) |
|
|
(22 |
) |
|
|
(18 |
) |
|
Total other income and (expense) |
|
|
(736 |
) |
|
|
(664 |
) |
|
|
(784 |
) |
|
Earnings Before Income Taxes |
|
|
3,066 |
|
|
|
2,604 |
|
|
|
2,722 |
|
Income taxes |
|
|
1,026 |
|
|
|
896 |
|
|
|
915 |
|
|
Consolidated Net Income |
|
|
2,040 |
|
|
|
1,708 |
|
|
|
1,807 |
|
Dividends on Preferred and Preference Stock of Subsidiaries |
|
|
65 |
|
|
|
65 |
|
|
|
65 |
|
|
Consolidated Net Income After Dividends on Preferred and Preference
Stock of Subsidiaries |
|
$ |
1,975 |
|
|
$ |
1,643 |
|
|
$ |
1,742 |
|
|
Common Stock Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share (EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS |
|
$ |
2.37 |
|
|
$ |
2.07 |
|
|
$ |
2.26 |
|
Diluted EPS |
|
|
2.36 |
|
|
|
2.06 |
|
|
|
2.25 |
|
|
Average number of shares of common stock outstanding (in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
832 |
|
|
|
795 |
|
|
|
771 |
|
Diluted |
|
|
837 |
|
|
|
796 |
|
|
|
775 |
|
|
Cash dividends paid per share of common stock |
|
$ |
1.8025 |
|
|
$ |
1.7325 |
|
|
$ |
1.6625 |
|
|
The accompanying notes are an integral part of these financial statements.
II-44
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
|
|
|
|
Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income |
|
$ |
2,040 |
|
|
$ |
1,708 |
|
|
$ |
1,807 |
|
Adjustments to reconcile consolidated net income
to net cash provided from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization, total |
|
|
1,831 |
|
|
|
1,788 |
|
|
|
1,704 |
|
Deferred income taxes |
|
|
1,038 |
|
|
|
25 |
|
|
|
215 |
|
Deferred revenues |
|
|
(103 |
) |
|
|
(54 |
) |
|
|
120 |
|
Allowance for equity funds used during construction |
|
|
(194 |
) |
|
|
(200 |
) |
|
|
(152 |
) |
Leveraged lease (income) losses |
|
|
(18 |
) |
|
|
(31 |
) |
|
|
85 |
|
Gain on disposition of lease termination |
|
|
|
|
|
|
(26 |
) |
|
|
|
|
Loss on extinguishment of debt |
|
|
|
|
|
|
17 |
|
|
|
|
|
Pension, postretirement, and other employee benefits |
|
|
(614 |
) |
|
|
(3 |
) |
|
|
21 |
|
Stock based compensation expense |
|
|
33 |
|
|
|
23 |
|
|
|
20 |
|
Hedge settlements |
|
|
2 |
|
|
|
(19 |
) |
|
|
15 |
|
Generation construction screening costs |
|
|
(51 |
) |
|
|
(22 |
) |
|
|
|
|
Other, net |
|
|
86 |
|
|
|
102 |
|
|
|
(108 |
) |
Changes in certain current assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
-Receivables |
|
|
80 |
|
|
|
585 |
|
|
|
(176 |
) |
-Fossil fuel stock |
|
|
135 |
|
|
|
(432 |
) |
|
|
(303 |
) |
-Materials and supplies |
|
|
(30 |
) |
|
|
(39 |
) |
|
|
(23 |
) |
-Other current assets |
|
|
(17 |
) |
|
|
(47 |
) |
|
|
(36 |
) |
-Accounts payable |
|
|
4 |
|
|
|
(125 |
) |
|
|
(74 |
) |
-Accrued taxes |
|
|
(308 |
) |
|
|
(95 |
) |
|
|
293 |
|
-Accrued compensation |
|
|
180 |
|
|
|
(226 |
) |
|
|
36 |
|
-Other current liabilities |
|
|
(103 |
) |
|
|
334 |
|
|
|
20 |
|
|
Net cash provided from operating activities |
|
|
3,991 |
|
|
|
3,263 |
|
|
|
3,464 |
|
|
Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Property additions |
|
|
(4,086 |
) |
|
|
(4,670 |
) |
|
|
(3,961 |
) |
Investment in restricted cash from revenue bonds |
|
|
(50 |
) |
|
|
(55 |
) |
|
|
(96 |
) |
Distribution of restricted cash from revenue bonds |
|
|
25 |
|
|
|
119 |
|
|
|
69 |
|
Nuclear decommissioning trust fund purchases |
|
|
(2,009 |
) |
|
|
(1,234 |
) |
|
|
(720 |
) |
Nuclear decommissioning trust fund sales |
|
|
2,004 |
|
|
|
1,228 |
|
|
|
712 |
|
Proceeds from property sales |
|
|
18 |
|
|
|
340 |
|
|
|
34 |
|
Cost of removal, net of salvage |
|
|
(125 |
) |
|
|
(119 |
) |
|
|
(123 |
) |
Change in construction payables |
|
|
(51 |
) |
|
|
215 |
|
|
|
83 |
|
Other investing activities |
|
|
18 |
|
|
|
(143 |
) |
|
|
(124 |
) |
|
Net cash used for investing activities |
|
|
(4,256 |
) |
|
|
(4,319 |
) |
|
|
(4,126 |
) |
|
Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in notes payable, net |
|
|
659 |
|
|
|
(306 |
) |
|
|
(314 |
) |
Proceeds |
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt issuances |
|
|
3,151 |
|
|
|
3,042 |
|
|
|
3,687 |
|
Common stock issuances |
|
|
772 |
|
|
|
1,286 |
|
|
|
474 |
|
Redemptions |
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
(2,966 |
) |
|
|
(1,234 |
) |
|
|
(1,469 |
) |
Redeemable preferred stock |
|
|
|
|
|
|
|
|
|
|
(125 |
) |
Payment of common stock dividends |
|
|
(1,496 |
) |
|
|
(1,369 |
) |
|
|
(1,280 |
) |
Payment of dividends on preferred and preference stock of
subsidiaries |
|
|
(65 |
) |
|
|
(65 |
) |
|
|
(66 |
) |
Other financing activities |
|
|
(33 |
) |
|
|
(25 |
) |
|
|
(29 |
) |
|
Net cash provided from financing activities |
|
|
22 |
|
|
|
1,329 |
|
|
|
878 |
|
|
Net Change in Cash and Cash Equivalents |
|
|
(243 |
) |
|
|
273 |
|
|
|
216 |
|
Cash and Cash Equivalents at Beginning of Year |
|
|
690 |
|
|
|
417 |
|
|
|
201 |
|
|
Cash and Cash Equivalents at End of Year |
|
$ |
447 |
|
|
$ |
690 |
|
|
$ |
417 |
|
|
The accompanying notes are an integral part of these financial statements.
II-45
CONSOLIDATED BALANCE SHEETS
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
Assets |
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
447 |
|
|
$ |
690 |
|
Restricted cash and cash equivalents |
|
|
68 |
|
|
|
43 |
|
Receivables |
|
|
|
|
|
|
|
|
Customer accounts receivable |
|
|
1,140 |
|
|
|
953 |
|
Unbilled revenues |
|
|
420 |
|
|
|
394 |
|
Under recovered regulatory clause revenues |
|
|
209 |
|
|
|
333 |
|
Other accounts and notes receivable |
|
|
285 |
|
|
|
375 |
|
Accumulated provision for uncollectible
accounts |
|
|
(25 |
) |
|
|
(25 |
) |
Fossil fuel stock, at average cost |
|
|
1,308 |
|
|
|
1,447 |
|
Materials and supplies, at average cost |
|
|
827 |
|
|
|
794 |
|
Vacation pay |
|
|
151 |
|
|
|
145 |
|
Prepaid expenses |
|
|
784 |
|
|
|
508 |
|
Other regulatory assets, current |
|
|
210 |
|
|
|
167 |
|
Other current assets |
|
|
59 |
|
|
|
49 |
|
|
Total current assets |
|
|
5,883 |
|
|
|
5,873 |
|
|
Property, Plant, and Equipment: |
|
|
|
|
|
|
|
|
In service |
|
|
56,731 |
|
|
|
53,588 |
|
Less accumulated depreciation |
|
|
20,174 |
|
|
|
19,121 |
|
|
Plant in service, net of depreciation |
|
|
36,557 |
|
|
|
34,467 |
|
Nuclear fuel, at amortized cost |
|
|
670 |
|
|
|
593 |
|
Construction work in progress |
|
|
4,775 |
|
|
|
4,170 |
|
|
Total property, plant, and equipment |
|
|
42,002 |
|
|
|
39,230 |
|
|
Other Property and Investments: |
|
|
|
|
|
|
|
|
Nuclear decommissioning trusts, at fair value |
|
|
1,370 |
|
|
|
1,070 |
|
Leveraged leases |
|
|
624 |
|
|
|
610 |
|
Miscellaneous property and investments |
|
|
277 |
|
|
|
283 |
|
|
Total other property and investments |
|
|
2,271 |
|
|
|
1,963 |
|
|
Deferred Charges and Other Assets: |
|
|
|
|
|
|
|
|
Deferred charges related to income taxes |
|
|
1,280 |
|
|
|
1,047 |
|
Prepaid pension costs |
|
|
88 |
|
|
|
|
|
Unamortized debt issuance expense |
|
|
178 |
|
|
|
208 |
|
Unamortized loss on reacquired debt |
|
|
274 |
|
|
|
255 |
|
Deferred under recovered regulatory clause revenues |
|
|
218 |
|
|
|
373 |
|
Other regulatory assets, deferred |
|
|
2,402 |
|
|
|
2,702 |
|
Other deferred charges and assets |
|
|
436 |
|
|
|
395 |
|
|
Total deferred charges and other assets |
|
|
4,876 |
|
|
|
4,980 |
|
|
Total Assets |
|
$ |
55,032 |
|
|
$ |
52,046 |
|
|
The accompanying notes are an integral part of these financial statements.
II-46
CONSOLIDATED BALANCE SHEETS
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Securities due within one year |
|
$ |
1,301 |
|
|
$ |
1,113 |
|
Notes payable |
|
|
1,297 |
|
|
|
639 |
|
Accounts payable |
|
|
1,275 |
|
|
|
1,329 |
|
Customer deposits |
|
|
332 |
|
|
|
331 |
|
Accrued taxes |
|
|
|
|
|
|
|
|
Accrued income taxes |
|
|
8 |
|
|
|
13 |
|
Unrecognized tax benefits |
|
|
187 |
|
|
|
166 |
|
Other accrued taxes |
|
|
440 |
|
|
|
398 |
|
Accrued interest |
|
|
225 |
|
|
|
218 |
|
Accrued vacation pay |
|
|
194 |
|
|
|
184 |
|
Accrued compensation |
|
|
438 |
|
|
|
248 |
|
Liabilities from risk management activities |
|
|
152 |
|
|
|
125 |
|
Other regulatory liabilities, current |
|
|
88 |
|
|
|
528 |
|
Other current liabilities |
|
|
535 |
|
|
|
292 |
|
|
Total current liabilities |
|
|
6,472 |
|
|
|
5,584 |
|
|
Long-Term Debt (See accompanying statements) |
|
|
18,154 |
|
|
|
18,131 |
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
|
|
|
|
Accumulated deferred income taxes |
|
|
7,554 |
|
|
|
6,455 |
|
Deferred credits related to income taxes |
|
|
235 |
|
|
|
248 |
|
Accumulated deferred investment tax credits |
|
|
509 |
|
|
|
448 |
|
Employee benefit obligations |
|
|
1,580 |
|
|
|
2,304 |
|
Asset retirement obligations |
|
|
1,257 |
|
|
|
1,201 |
|
Other cost of removal obligations |
|
|
1,158 |
|
|
|
1,091 |
|
Other regulatory liabilities, deferred |
|
|
312 |
|
|
|
278 |
|
Other deferred credits and liabilities |
|
|
517 |
|
|
|
346 |
|
|
Total deferred credits and other liabilities |
|
|
13,122 |
|
|
|
12,371 |
|
|
Total Liabilities |
|
|
37,748 |
|
|
|
36,086 |
|
|
Redeemable Preferred Stock of Subsidiaries (See
accompanying statements) |
|
|
375 |
|
|
|
375 |
|
|
Total Stockholders Equity (See accompanying statements) |
|
|
16,909 |
|
|
|
15,585 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
55,032 |
|
|
$ |
52,046 |
|
|
Commitments and Contingent Matters (See notes) |
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
II-47
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
(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 (3.39% at 1/1/11) due 2042 |
|
|
|
|
206 |
|
|
|
206 |
|
|
|
|
|
|
|
|
|
|
Total long-term debt payable to affiliated trusts |
|
|
|
|
412 |
|
|
|
412 |
|
|
|
|
|
|
|
|
|
|
Long-term senior notes and debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity |
|
Interest Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
4.70% |
|
|
|
|
|
|
102 |
|
|
|
|
|
|
|
|
|
2011 |
|
4.00% to 5.57% |
|
|
304 |
|
|
|
304 |
|
|
|
|
|
|
|
|
|
2012 |
|
4.85% to 6.25% |
|
|
1,778 |
|
|
|
1,778 |
|
|
|
|
|
|
|
|
|
2013 |
|
1.30% to 6.00% |
|
|
1,436 |
|
|
|
936 |
|
|
|
|
|
|
|
|
|
2014 |
|
4.15% to 4.90% |
|
|
425 |
|
|
|
425 |
|
|
|
|
|
|
|
|
|
2015 |
|
2.38% to 5.75% |
|
|
1,184 |
|
|
|
1,025 |
|
|
|
|
|
|
|
|
|
2016 through 2048 |
|
2.25% to 8.20% |
|
|
9,438 |
|
|
|
8,822 |
|
|
|
|
|
|
|
|
|
Adjustable rates (at 1/1/11): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
0.35% to 0.97% |
|
|
|
|
|
|
990 |
|
|
|
|
|
|
|
|
|
2011 |
|
0.56% to 0.78% |
|
|
915 |
|
|
|
790 |
|
|
|
|
|
|
|
|
|
2013 |
|
0.62% |
|
|
350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2040 |
|
0.44% |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term senior notes and debt |
|
|
|
|
15,880 |
|
|
|
15,172 |
|
|
|
|
|
|
|
|
|
|
Other long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pollution control revenue bonds |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity |
|
Interest Rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 through 2049 |
|
0.80% to 6.00% |
|
|
1,807 |
|
|
|
1,973 |
|
|
|
|
|
|
|
|
|
Variable rates (at 1/1/11): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 through 2041 |
|
0.26% to 0.51% |
|
|
1,284 |
|
|
|
1,612 |
|
|
|
|
|
|
|
|
|
|
Total other long-term debt |
|
|
|
|
3,091 |
|
|
|
3,585 |
|
|
|
|
|
|
|
|
|
|
Capitalized lease obligations |
|
|
|
|
99 |
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
Unamortized debt (discount), net |
|
|
|
|
(27 |
) |
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
Total long-term debt (annual interest
requirement $876 million) |
|
|
|
|
19,455 |
|
|
|
19,244 |
|
|
|
|
|
|
|
|
|
Less amount due within one year |
|
|
|
|
1,301 |
|
|
|
1,113 |
|
|
|
|
|
|
|
|
|
|
Long-term debt excluding amount due within one year |
|
|
|
|
18,154 |
|
|
|
18,131 |
|
|
|
51.2 |
% |
|
|
53.2 |
% |
|
II-48
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(continued)
At December 31, 2010 and 2009
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(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 5.20% to 5.83% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized 28 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding 12 million shares: $25 stated value |
|
|
294 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
Total redeemable preferred stock of subsidiaries
(annual dividend requirement $20 million) |
|
|
375 |
|
|
|
375 |
|
|
|
1.1 |
|
|
|
1.1 |
|
|
Common Stockholders Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, par value $5 per share |
|
|
4,219 |
|
|
|
4,101 |
|
|
|
|
|
|
|
|
|
Authorized 1 billion shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issued 2010: 844 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: 820 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury 2010: 0.5 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: 0.5 million shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid-in capital |
|
|
3,702 |
|
|
|
2,995 |
|
|
|
|
|
|
|
|
|
Treasury, at cost |
|
|
(15 |
) |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
Retained earnings |
|
|
8,366 |
|
|
|
7,885 |
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss) |
|
|
(70 |
) |
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
Total common stockholders equity |
|
|
16,202 |
|
|
|
14,878 |
|
|
|
45.7 |
|
|
|
43.6 |
|
|
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 |
|
|
|
2.0 |
|
|
|
2.1 |
|
|
Total stockholders equity |
|
|
16,909 |
|
|
|
15,585 |
|
|
|
|
|
|
|
|
|
|
Total Capitalization |
|
$ |
35,438 |
|
|
$ |
34,091 |
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
The accompanying notes are an integral part of these financial statements.
II-49
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 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, 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 loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(75 |
) |
|
|
|
|
|
|
(75 |
) |
Stock issued |
|
|
14,113 |
|
|
|
|
|
|
|
71 |
|
|
|
402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
473 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
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 |
|
|
|
1,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,287 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
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 |
|
Net income after dividends
on preferred and preference
stock of subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,975 |
|
|
|
|
|
|
|
|
|
|
|
1,975 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
18 |
|
Stock issued |
|
|
23,662 |
|
|
|
|
|
|
|
118 |
|
|
|
654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
772 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52 |
|
Cash dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,496 |
) |
|
|
|
|
|
|
|
|
|
|
(1,496 |
) |
Other |
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
Balance at December 31, 2010 |
|
|
843,814 |
|
|
|
(474 |
) |
|
$ |
4,219 |
|
|
$ |
3,702 |
|
|
$ |
(15 |
) |
|
$ |
8,366 |
|
|
$ |
(70 |
) |
|
$ |
707 |
|
|
$ |
16,909 |
|
|
The accompanying notes are an integral part of these financial statements.
II-50
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2010, 2009, and 2008
Southern Company and Subsidiary Companies 2010 Annual Report
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
|
|
|
|
Consolidated Net Income |
|
$ |
2,040 |
|
|
$ |
1,708 |
|
|
$ |
1,807 |
|
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
Qualifying hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value, net of tax of $-, $(3), and $(19), respectively |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
(30 |
) |
Reclassification adjustment for amounts included in net income, net of tax of $9,
$18, and $7, respectively |
|
|
15 |
|
|
|
28 |
|
|
|
11 |
|
Marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value, net of tax of $(2), $1, and $(4), respectively |
|
|
(3 |
) |
|
|
4 |
|
|
|
(7 |
) |
Pension and other postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
Benefit plan net gain (loss),net of tax of $1, $(8), and $(32), respectively |
|
|
6 |
|
|
|
(12 |
) |
|
|
(51 |
) |
Reclassification adjustment for amounts included in net income, net of tax of $1,
$1, and $1, respectively |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
Total other comprehensive income (loss) |
|
|
18 |
|
|
|
17 |
|
|
|
(75 |
) |
|
Dividends on preferred and preference stock of subsidiaries |
|
|
(65 |
) |
|
|
(65 |
) |
|
|
(65 |
) |
|
Consolidated Comprehensive Income |
|
$ |
1,993 |
|
|
$ |
1,660 |
|
|
$ |
1,667 |
|
|
The accompanying notes are an integral part of these financial statements.
II-51
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2010 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 has an equity
investment, but 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 generally accepted accounting principles (GAAP) in the U.S. and comply
with the accounting policies and practices prescribed by their respective commissions. The
preparation of financial statements in conformity with GAAP requires the use of estimates, and the
actual results may differ from those estimates.
II-52
NOTES (continued)
Southern Company and Subsidiary Companies 2010 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Note |
|
|
|
(in millions) |
|
|
|
|
|
Deferred income tax charges |
|
$ |
1,204 |
|
|
$ |
1,048 |
|
|
|
(a |
) |
Deferred income tax charges Medicare subsidy |
|
|
82 |
|
|
|
|
|
|
|
(k |
) |
Asset retirement obligations-asset |
|
|
79 |
|
|
|
125 |
|
|
|
(a,i |
) |
Asset retirement obligations-liability |
|
|
(82 |
) |
|
|
(47 |
) |
|
|
(a,i |
) |
Other cost of removal obligations |
|
|
(1,188 |
) |
|
|
(1,307 |
) |
|
|
(a |
) |
Deferred income tax credits |
|
|
(237 |
) |
|
|
(249 |
) |
|
|
(a |
) |
Loss on reacquired debt |
|
|
274 |
|
|
|
255 |
|
|
|
(b |
) |
Vacation pay |
|
|
151 |
|
|
|
145 |
|
|
|
(c,i |
) |
Under recovered regulatory clause revenues |
|
|
27 |
|
|
|
40 |
|
|
|
(d |
) |
Over recovered regulatory clause revenues |
|
|
(40 |
) |
|
|
(218 |
) |
|
|
(d |
) |
Building leases |
|
|
45 |
|
|
|
47 |
|
|
|
(f |
) |
Generating plant outage costs |
|
|
31 |
|
|
|
39 |
|
|
|
(d |
) |
Under recovered storm damage costs |
|
|
8 |
|
|
|
22 |
|
|
|
(d |
) |
Property damage reserves |
|
|
(216 |
) |
|
|
(157 |
) |
|
|
(h |
) |
Fuel hedging-asset |
|
|
211 |
|
|
|
187 |
|
|
|
(d |
) |
Fuel hedging-liability |
|
|
(7 |
) |
|
|
(2 |
) |
|
|
(d |
) |
Other assets |
|
|
171 |
|
|
|
156 |
|
|
|
(d |
) |
Environmental remediation-asset |
|
|
67 |
|
|
|
68 |
|
|
|
(h,i |
) |
Environmental remediation-liability |
|
|
(10 |
) |
|
|
(13 |
) |
|
|
(h |
) |
Environmental compliance cost recovery |
|
|
|
|
|
|
(96 |
) |
|
|
(g |
) |
Other liabilities |
|
|
(13 |
) |
|
|
(51 |
) |
|
|
(j |
) |
Retiree benefit plans |
|
|
2,041 |
|
|
|
2,268 |
|
|
|
(e,i |
) |
|
Total assets (liabilities), net |
|
$ |
2,598 |
|
|
$ |
2,260 |
|
|
|
|
|
|
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, and
deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset
retirement and other cost of removal liabilities will be settled and trued up following completion of the related
activities. Other cost of removal obligations include $92 million at Georgia Power that will be amortized over a
three-year period beginning January 1, 2011 in accordance with a Georgia PSC order. See Note 3 under Retail
Regulatory Matters Georgia Power Retail Rate Plans 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) |
|
Deferred revenue associated with the levelization of Georgia Powers environmental compliance cost recovery
(ECCR) tariff revenue for the years 2008 through 2010 in accordance with a Georgia PSC order. |
|
(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. |
|
(k) |
|
Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 14 years. See Note
5 under Current and Deferred Income Taxes for additional information. |
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 (OCI) related regulatory assets and
liabilities that are not specifically recoverable through regulated rates. In addition, the
traditional operating company would be required to determine if any impairment to other assets,
including plant, exists and write down the assets, if impaired, to their fair values. All
regulatory assets and liabilities are to be reflected in rates. See Note 3 under Retail
Regulatory
II-53
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Matters Alabama Power, Retail Regulatory Matters Georgia Power, and Retail Regulatory
Matters Mississippi Power Integrated Coal Gasification Combined Cycle for additional
information.
Revenues
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate
contract periods. Energy and other revenues are recognized as services are provided. Unbilled
revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for
the traditional operating companies include provisions to adjust billings for fluctuations in fuel
costs, fuel hedging, the energy component of purchased power costs, and certain other costs.
Revenues are adjusted for differences between these actual costs and amounts billed in current
regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance
sheets and are recovered or returned to customers through adjustments to the billing factors.
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 $23 million in 2010, $24 million in 2009, and $23
million in 2008. At December 31, 2010, all ITCs available to reduce federal income taxes payable
had been utilized.
Under the American Recovery and Reinvestment Act of 2009, certain projects at certain Southern
Company subsidiaries are eligible for ITCs or cash grants. These subsidiaries 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 subsidiaries 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. These basis differences 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.
II-54
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Southern Companys property, plant, and equipment consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Generation |
|
$ |
30,121 |
|
|
$ |
28,204 |
|
Transmission |
|
|
7,835 |
|
|
|
7,380 |
|
Distribution |
|
|
14,870 |
|
|
|
14,335 |
|
General |
|
|
3,116 |
|
|
|
2,917 |
|
Plant acquisition adjustment |
|
|
43 |
|
|
|
43 |
|
|
Utility plant in service |
|
|
55,985 |
|
|
|
52,879 |
|
|
Information technology equipment and software |
|
|
216 |
|
|
|
182 |
|
Communications equipment |
|
|
423 |
|
|
|
423 |
|
Other |
|
|
107 |
|
|
|
104 |
|
|
Other plant in service |
|
|
746 |
|
|
|
709 |
|
|
Total plant in service |
|
$ |
56,731 |
|
|
$ |
53,588 |
|
|
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 and Georgia Power defer and amortize
nuclear refueling costs over the units operating cycle. 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.
The amount of non-cash property
additions recognized for the years ended December 31, 2010, 2009, and
2008 was $427 million, $370 million, and $309 million, respectively. These amounts are comprised of
construction related accounts payable outstanding at each year end together with retention amounts
accrued during the respective year.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using
composite straight-line rates, which approximated 3.3% in 2010, 3.2% in 2009, and 3.2% in 2008.
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 $19.7 billion and $18.7 billion at December 31,
2010 and 2009, respectively. When property subject to composite depreciation is retired or
otherwise disposed of in the normal course of business, its original cost, together with the cost
of removal, less salvage, is charged to accumulated depreciation. For other property dispositions,
the applicable cost and accumulated depreciation are removed from the balance sheet accounts and a
gain or loss is recognized. Minor items of property included in the original cost of the plant are
retired when the related property unit is retired.
In August 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a
portion of its regulatory liability related to other cost of removal obligations. See Note 3 under
Retail Regulatory Matters Georgia Power Retail Rate Plans for additional information.
Depreciation of the original cost of other plant in service is provided primarily on a
straight-line basis over estimated useful lives ranging from three to 30 years. Accumulated
depreciation for other plant in service totaled $441 million and $419 million at December 31, 2010
and 2009, 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 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 Retail Rate Plans for additional information related to Georgia
Powers cost of removal regulatory liability.
II-55
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
The liability recognized to retire long-lived assets primarily relates to the Companys nuclear
facilities, Plants Farley, Hatch, and Vogtle. In addition, the Company has retirement obligations
related to various landfill sites, ash ponds, 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:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Balance at beginning of year |
|
$ |
1,206 |
|
|
$ |
1,185 |
|
Liabilities incurred |
|
|
|
|
|
|
2 |
|
Liabilities settled |
|
|
(16 |
) |
|
|
(10 |
) |
Accretion |
|
|
78 |
|
|
|
77 |
|
Cash flow revisions |
|
|
(2 |
) |
|
|
(48 |
) |
|
Balance at end of year |
|
$ |
1,266 |
|
|
$ |
1,206 |
|
|
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 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 or unrealized, are recorded in the regulatory
liability for asset retirement obligations in the balance sheets and are not included in net income
or OCI. Fair value adjustments and realized gains and losses are determined on a specific
identification basis.
The Funds at Georgia Power participate in a securities lending program through the managers of the
Funds. Under this program, the Funds investment securities are loaned to investment brokers for a
fee. Securities so loaned are fully collateralized by cash, letters of credit, and securities
issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of
December 31, 2010 and 2009, approximately $141 million and $14 million, respectively, of the fair
market value of the Funds securities were on loan and pledged to creditors under the Funds
managers securities lending program. The fair value of the collateral received
was approximately $144 million and $14 million at
December 31, 2010 and 2009, respectively,
and can only be sold upon the return of the loaned securities. The collateral received is treated as a non-cash item in
the statements of cash flows.
At December 31, 2010, investment securities in the Funds totaled $1.4 billion consisting of equity
securities of $664 million, debt securities of $632 million, and $74 million of other securities.
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.
These amounts include the investment securities pledged to creditors and collateral received, and
exclude receivables related to investment income and pending investment sales, and payables related
to pending investment purchases and the lending pool.
II-56
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Sales of the securities held in the Funds resulted in cash proceeds of $2.0 billion, $1.2 billion,
and $712 million in 2010, 2009, and 2008, respectively, all of which were reinvested. For 2010,
fair value increases, including reinvested interest and dividends and excluding the Funds
expenses, were $139 million, of which $6 million related to securities held in the Funds at
December 31, 2010. For 2009, fair value increases, including reinvested interest and dividends and
excluding the Funds 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 the Funds expenses, were $(278) million. While the investment
securities held in the Funds are reported as trading securities, the Funds continue to be managed
with a long-term focus. Accordingly, all purchases and sales within the Funds are presented
separately in the statements of cash flows as investing cash flows, consistent with the nature of
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 Funds will
provide the minimum funding amounts prescribed by the NRC.
At December 31, 2010, the accumulated provisions for decommissioning were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Farley |
|
|
Plant Hatch |
|
|
Plant Vogtle |
|
|
|
(in millions) |
|
External trust funds |
|
$ |
553 |
|
|
$ |
360 |
|
|
$ |
206 |
|
Internal reserves |
|
|
24 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
577 |
|
|
$ |
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 Alabama Powers 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 in June 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 $575
million and $420 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Amounts
expensed were $3 million annually for Plant Vogtle Units 1 and 2 for 2008 through 2010. Effective
for the years 2011 through 2013, the annual decommissioning cost for ratemaking is $2 million for
Plant Hatch. Georgia Power projects the external trust funds for Plant Vogtle Units 1 and 2 would
be adequate to meet the decommissioning obligations of the NRC with no further contributions.
Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5%
and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and
4.4% for Alabama Power and Georgia Power, respectively. As a result of license extensions, amounts
previously contributed to the external trust funds for Plant Farley are currently projected to be
adequate to meet the decommissioning obligations.
II-57
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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 standard
interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were
12.5%, 15.3%, and 11.2% of net income for 2010, 2009, and 2008, respectively.
Cash payments for interest totaled $789 million, $788 million, and $787 million in 2010, 2009, and
2008, respectively, net of amounts capitalized of $86 million, $84 million, and $71 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 $32 million in 2010 and $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 2010 and 2009, such
additional accruals totaled $48 million and $40 million, respectively, all at Alabama Power. There
were no material accruals for 2008. See Note 3 under Retail Regulatory Matters Alabama Power
Natural Disaster Reserve for additional information regarding Alabama Powers natural disaster
reserve.
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:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Net rentals receivable |
|
$ |
475 |
|
|
$ |
487 |
|
Unearned income |
|
|
(207 |
) |
|
|
(218 |
) |
|
Investment in leveraged leases |
|
|
268 |
|
|
|
269 |
|
Deferred taxes from leveraged leases |
|
|
(223 |
) |
|
|
(211 |
) |
|
Net investment in leveraged leases |
|
$ |
45 |
|
|
$ |
58 |
|
|
II-58
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
A summary of the components of income from domestic leveraged leases was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Pretax leveraged lease income |
|
$ |
4 |
|
|
$ |
12 |
|
|
$ |
14 |
|
Income tax expense |
|
|
(3 |
) |
|
|
(5 |
) |
|
|
(6 |
) |
|
Net leveraged lease income |
|
$ |
1 |
|
|
$ |
7 |
|
|
$ |
8 |
|
|
Southern Companys net investment in international leveraged leases consists of the following at
December 31:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Net rentals receivable |
|
$ |
733 |
|
|
$ |
734 |
|
Unearned income |
|
|
(377 |
) |
|
|
(393 |
) |
|
Investment in leveraged leases |
|
|
356 |
|
|
|
341 |
|
Current taxes payable |
|
|
|
|
|
|
|
|
Deferred taxes from leveraged leases |
|
|
(40 |
) |
|
|
(40 |
) |
|
Net investment in leveraged leases |
|
$ |
316 |
|
|
$ |
301 |
|
|
A summary of the components of income from international leveraged leases was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Pretax leveraged lease income (loss) |
|
$ |
14 |
|
|
$ |
19 |
|
|
$ |
(99 |
) |
Income tax benefit (expense) |
|
|
(5 |
) |
|
|
(7 |
) |
|
|
35 |
|
|
Net leveraged lease income (loss) |
|
$ |
9 |
|
|
$ |
12 |
|
|
$ |
(64 |
) |
|
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, electricity purchases and sales, and
occasionally foreign currency exchange rates. All derivative financial instruments are recognized
as either assets or liabilities (included in Other or shown separately as Risk Management
Activities) and are measured at fair value. See Note 10 for additional information.
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 OCI or regulatory assets and liabilities, respectively, until the
hedged transactions occur. Any
II-59
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
ineffectiveness arising from cash flow hedges is recognized currently in net income. Other
derivative contracts 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.
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, 2010, 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 OCI (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, 2009 |
|
$ |
(49 |
) |
|
$ |
10 |
|
|
$ |
(49 |
) |
|
$ |
(88 |
) |
Current period change |
|
|
14 |
|
|
|
(3 |
) |
|
|
7 |
|
|
|
18 |
|
|
Balance at December 31, 2010 |
|
$ |
(35 |
) |
|
$ |
7 |
|
|
$ |
(42 |
) |
|
$ |
(70 |
) |
|
Variable Interest Entities
Effective January 1, 2010, the traditional operating companies and Southern Power adopted new
accounting guidance which modified the consolidation model and expanded disclosures related to
variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the
VIE when it has both the power to direct the activities of the VIE that most significantly impact
the VIEs economic performance and the obligation to absorb losses or the right to receive benefits
from the VIE that could potentially be significant to the VIE. The adoption of this new accounting
guidance did not result in the traditional operating companies or Southern Power consolidating any
VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs.
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
reflected in long-term debt in the balance sheets.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all
employees. This qualified pension plan is funded in accordance with requirements of the Employee
Retirement Income Security Act of 1974, as amended (ERISA). In December 2010, the traditional
operating companies and certain other subsidiaries contributed approximately $620 million to the
qualified pension plan. No contributions to the qualified pension plan are expected for the year
ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for
a selected group of management and highly compensated employees. Benefits under these
non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides
certain medical care and life insurance benefits for retired employees through other postretirement
benefit plans. The traditional operating companies fund related other postretirement trusts to the
extent required by their respective regulatory commissions. For the year ending December 31, 2011,
other postretirement trust contributions are expected to total approximately $31 million.
II-60
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
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 2007 for the 2008 plan year using a discount rate of 6.30% and an annual
salary increase of 3.75%.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
Discount rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Pension plans |
|
|
5.52 |
% |
|
|
5.93 |
% |
|
|
6.75 |
% |
Other postretirement benefit plans |
|
|
5.40 |
|
|
|
5.83 |
|
|
|
6.75 |
|
Annual salary increase |
|
|
3.84 |
|
|
|
4.18 |
|
|
|
3.75 |
|
Long-term return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Pension plans |
|
|
8.75 |
|
|
|
8.50 |
|
|
|
8.50 |
|
Other postretirement benefit plans |
|
|
7.40 |
|
|
|
7.51 |
|
|
|
7.59 |
|
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit
plan assets using a financial model to project the expected return on each current investment
portfolio. The analysis projects an expected rate of return on each of seven different asset
classes in order to arrive at the expected return on the entire portfolio relying on each trusts
target asset allocation and reasonable capital market assumptions. The financial model is based on
four key inputs: anticipated returns by asset class (based in part on historical returns), each
trusts target asset allocation, an anticipated inflation rate, and the projected impact of a
periodic rebalancing of each trusts portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations
(APBO) was a weighted average medical care cost trend rate of 8.25% for 2011, decreasing gradually
to 5.0% through the year 2019 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, 2010 as follows:
|
|
|
|
|
|
|
|
|
|
|
1 Percent |
|
1 Percent |
|
|
Increase |
|
Decrease |
|
|
(in millions) |
|
Benefit obligation |
|
$ |
128 |
|
|
$ |
108 |
|
Service and interest costs |
|
|
7 |
|
|
|
6 |
|
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $6.7 billion in 2010 and $6.3
billion in 2009. Changes in the projected benefit obligations and the fair value of plan assets
during the plan years ended December 31, 2010 and 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Change in benefit obligation |
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
6,758 |
|
|
$ |
5,879 |
|
Service cost |
|
|
172 |
|
|
|
146 |
|
Interest cost |
|
|
391 |
|
|
|
387 |
|
Benefits paid |
|
|
(296 |
) |
|
|
(282 |
) |
Actuarial loss (gain) |
|
|
198 |
|
|
|
628 |
|
|
Balance at end of year |
|
|
7,223 |
|
|
|
6,758 |
|
|
Change in plan assets |
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
5,627 |
|
|
|
5,093 |
|
Actual return (loss) on plan assets |
|
|
859 |
|
|
|
792 |
|
Employer contributions |
|
|
644 |
|
|
|
24 |
|
Benefits paid |
|
|
(296 |
) |
|
|
(282 |
) |
|
Fair value of plan assets at end of year |
|
|
6,834 |
|
|
|
5,627 |
|
|
Accrued liability |
|
$ |
(389 |
) |
|
$ |
(1,131 |
) |
|
At December 31, 2010, the projected benefit obligations for the qualified and non-qualified pension
plans were $6.7 billion and $0.5 billion, respectively. All pension plan assets are related to the
qualified pension plan.
II-61
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Amounts recognized in the balance sheets at December 31, 2010 and 2009 related to the Companys
pension plans consist of the following:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
(in millions) |
|
Prepaid pension costs |
|
$ |
88 |
|
|
$ |
|
|
Other regulatory assets, deferred |
|
|
1,749 |
|
|
|
1,894 |
|
Other current liabilities |
|
|
(28 |
) |
|
|
(25 |
) |
Employee benefit obligations |
|
|
(449 |
) |
|
|
(1,106 |
) |
Accumulated OCI |
|
|
68 |
|
|
|
74 |
|
|
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31,
2010 and 2009 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 2011.
|
|
|
|
|
|
|
|
|
|
|
Prior Service Cost |
|
Net (Gain) Loss |
|
|
(in millions) |
Balance at December 31, 2010: |
|
|
|
|
|
|
|
|
Accumulated OCI |
|
$ |
8 |
|
|
$ |
60 |
|
Regulatory assets |
|
|
159 |
|
|
|
1,590 |
|
|
Total |
|
$ |
167 |
|
|
$ |
1,650 |
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009: |
|
|
|
|
|
|
|
|
Accumulated OCI |
|
$ |
10 |
|
|
$ |
64 |
|
Regulatory assets |
|
|
188 |
|
|
|
1,706 |
|
|
Total |
|
$ |
198 |
|
|
$ |
1,770 |
|
|
|
|
|
|
|
|
|
|
|
Estimated amortization in net periodic
pension cost in 2011: |
|
|
|
|
|
|
|
|
Accumulated OCI |
|
$ |
1 |
|
|
$ |
1 |
|
Regulatory assets |
|
|
31 |
|
|
|
20 |
|
|
Total |
|
$ |
32 |
|
|
$ |
21 |
|
|
The components of OCI and the changes in the balance of regulatory assets related to the defined
benefit pension plans for the years ended December 31, 2010 and 2009 are presented in the following
table:
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
Regulatory |
|
|
OCI |
|
Assets |
|
|
(in millions) |
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 |
|
Net gain |
|
|
(4 |
) |
|
|
(106 |
) |
Change in prior service costs |
|
|
|
|
|
|
2 |
|
Reclassification adjustments: |
|
|
|
|
|
|
|
|
Amortization of prior service costs |
|
|
(1 |
) |
|
|
(32 |
) |
Amortization of net gain |
|
|
(1 |
) |
|
|
(9 |
) |
|
Total reclassification adjustments |
|
|
(2 |
) |
|
|
(41 |
) |
|
Total change |
|
|
(6 |
) |
|
|
(145 |
) |
|
Balance at December 31, 2010 |
|
$ |
68 |
|
|
$ |
1,749 |
|
|
II-62
NOTES (continued)
Southern Company and Subsidiary Companies 2010 Annual Report
Components of net periodic pension cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
Service cost |
|
$ |
172 |
|
|
$ |
146 |
|
|
$ |
146 |
|
Interest cost |
|
|
391 |
|
|
|
387 |
|
|
|
348 |
|
Expected return on plan assets |
|
|
(552 |
) |
|
|
(541 |
) |
|
|
(525 |
) |
Recognized net loss |
|
|
10 |
|
|
|
7 |
|
|
|
9 |
|
Net amortization |
|
|
33 |
|
|
|
35 |
|
|
|
37 |
|
|
Net periodic pension cost |
|
$ |
54 |
|
|
$ |
34 |
|
|
$ |
15 |
|
|
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, 2010, estimated
benefit payments were as follows:
|
|
|
|
|
|
|
Benefit Payments |
|
|
(in millions) |
2011
|
|
$ |
335 |
|
2012
|
|
|
353 |
|
2013
|
|
|
372 |
|
<