10-Q 1 G28005-10Q.HTM FORM 10-Q corresp
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
         
Commission   Registrant, State of Incorporation,   I.R.S. Employer
File Number   Address and Telephone Number   Identification No.
1-3526
  The Southern Company   58-0690070
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    
 
       
1-3164
  Alabama Power Company   63-0004250
 
  (An Alabama Corporation)    
 
  600 North 18th Street    
 
  Birmingham, Alabama 35203    
 
  (205) 257-1000    
 
       
1-6468
  Georgia Power Company   58-0257110
 
  (A Georgia Corporation)    
 
  241 Ralph McGill Boulevard, N.E.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-6526    
 
       
001-31737
  Gulf Power Company   59-0276810
 
  (A Florida Corporation)    
 
  One Energy Place    
 
  Pensacola, Florida 32520    
 
  (850) 444-6111    
 
       
001-11229
  Mississippi Power Company   64-0205820
 
  (A Mississippi Corporation)    
 
  2992 West Beach    
 
  Gulfport, Mississippi 39501    
 
  (228) 864-1211    
 
       
333-98553
  Southern Power Company   58-2598670
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    

 


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     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
     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):
                 
    Large           Smaller
    Accelerated   Accelerated   Non-accelerated   Reporting
Registrant   Filer   Filer   Filer   Company
The Southern Company
  X            
Alabama Power Company
          X    
Georgia Power Company
          X    
Gulf Power Company
          X    
Mississippi Power Company
          X    
Southern Power Company
          X    
     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.)
             
    Description of   Shares Outstanding
Registrant   Common Stock   at September 30, 2011
The Southern Company
  Par Value $5 Per Share     861,928,103  
Alabama Power Company
  Par Value $40 Per Share     30,537,500  
Georgia Power Company
  Without Par Value     9,261,500  
Gulf Power Company
  Without Par Value     4,142,717  
Mississippi Power Company
  Without Par Value     1,121,000  
Southern Power Company
  Par Value $0.01 Per Share     1,000  
This combined Form 10-Q 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 registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2011
             
        Page
        Number
DEFINITIONS     5  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION     7  
 
           
 
  PART I — FINANCIAL INFORMATION        
 
           
Item 1.
  Financial Statements (Unaudited)        
Item 2.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations        
 
  The Southern Company and Subsidiary Companies        
 
 
Condensed Consolidated Statements of Income
    9  
 
 
Condensed Consolidated Statements of Cash Flows
    10  
 
 
Condensed Consolidated Balance Sheets
    11  
 
 
Condensed Consolidated Statements of Comprehensive Income
    13  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    14  
 
  Alabama Power Company        
 
 
Condensed Statements of Income
    39  
 
 
Condensed Statements of Comprehensive Income
    39  
 
 
Condensed Statements of Cash Flows
    40  
 
 
Condensed Balance Sheets
    41  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    43  
 
  Georgia Power Company        
 
 
Condensed Statements of Income
    60  
 
 
Condensed Statements of Comprehensive Income
    60  
 
 
Condensed Statements of Cash Flows
    61  
 
 
Condensed Balance Sheets
    62  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    64  
 
  Gulf Power Company        
 
 
Condensed Statements of Income
    84  
 
 
Condensed Statements of Comprehensive Income
    84  
 
 
Condensed Statements of Cash Flows
    85  
 
 
Condensed Balance Sheets
    86  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    88  
 
  Mississippi Power Company        
 
 
Condensed Statements of Income
    105  
 
 
Condensed Statements of Comprehensive Income
    105  
 
 
Condensed Statements of Cash Flows
    106  
 
 
Condensed Balance Sheets
    107  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    109  
 
  Southern Power Company and Subsidiary Companies        
 
 
Condensed Consolidated Statements of Income
    132  
 
 
Condensed Consolidated Statements of Comprehensive Income
    132  
 
 
Condensed Consolidated Statements of Cash Flows
    133  
 
 
Condensed Consolidated Balance Sheets
    134  
 
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
    136  
 
  Notes to the Condensed Financial Statements     148  
  Quantitative and Qualitative Disclosures about Market Risk     37  
 
Controls and Procedures
    37  

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2011
             
        Page  
        Number  
 
  PART II — OTHER INFORMATION        
  Legal Proceedings     185  
  Risk Factors     185  
Item 2.
  Unregistered Sales of Equity Securities and Use of Proceeds   Inapplicable  
Item 3.
  Defaults Upon Senior Securities   Inapplicable  
Item 5.
  Other Information   Inapplicable  
  Exhibits     186  
 
  Signatures     191  

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DEFINITIONS
     
Term   Meaning
2007 Retail Rate Plan
  Georgia Power’s retail rate plan for the years 2008 through 2010
2010 ARP
  Alternate Rate Plan approved by the Georgia PSC for Georgia Power which became effective January 1, 2011 and will continue through December 31, 2013
AFUDC
  Allowance for funds used during construction
Alabama Power
  Alabama Power Company
Clean Air Act
  Clean Air Act Amendments of 1990
DOE
  U.S. Department of Energy
Duke Energy
  Duke Energy Corporation
ECO Plan
  Mississippi Power’s Environmental Compliance Overview Plan
EPA
  U.S. Environmental Protection Agency
FERC
  Federal Energy Regulatory Commission
Form 10-K
  Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2010
GAAP
  Generally Accepted Accounting Principles
Georgia Power
  Georgia Power Company
Gulf Power
  Gulf Power Company
IGCC
  Integrated coal gasification combined cycle
IIC
  Intercompany Interchange Contract
Internal Revenue Code
  Internal Revenue Code of 1986, as amended
IRP
  Integrated Resource Plan
IRS
  Internal Revenue Service
KWH
  Kilowatt-hour
LIBOR
  London Interbank Offered Rate
Mississippi Power
  Mississippi Power Company
mmBtu
  Million British thermal unit
MW
  Megawatt
MWH
  Megawatt-hour
NCCR tariff
  Georgia Power’s Nuclear Construction Cost Recovery tariff, which became effective January 1, 2011, in accordance with the Georgia Nuclear Energy Financing Act
NDR
  Alabama Power’s natural disaster reserve
NRC
  Nuclear Regulatory Commission
NSR
  New Source Review
OCI
  Other Comprehensive Income
PEP
  Mississippi Power’s Performance Evaluation Plan
Plant Vogtle Units 3 and 4
  Two new nuclear generating units under construction at Plant
Vogtle
Power Pool
  The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA
  Power Purchase Agreement
PSC
  Public Service Commission
Rate CNP Environmental
  Alabama Power’s rate certificated new plant environmental
Rate ECR
  Alabama Power’s energy cost recovery rate mechanism
registrants
  Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCR
  Selective catalytic reduction
SCS
  Southern Company Services, Inc.

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Term   Meaning
SEC
  Securities and Exchange Commission
Southern Company
  The Southern Company
Southern Company system
  Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
SouthernLINC Wireless
  Southern Communications Services, Inc.
Southern Nuclear
  Southern Nuclear Operating Company, Inc.
Southern Power
  Southern Power Company
traditional operating companies
  Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse
  Westinghouse Electric Company LLC
wholesale revenues
  revenues generated from sales for resale

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q 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, current and proposed environmental regulations and related estimated expenditures, future earnings, access to sources of capital, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, 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, storm damage cost recovery and repairs, 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 and IRS audits;
 
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
  variations in demand for electricity, including those relating to weather, the general economy and recovery from the 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 Company’s 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 Company’s business resulting from terrorist incidents and the threat of terrorist incidents, including cyber intrusion;
 
  interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
 
  the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the availability or benefits of proposed DOE loan guarantees;
 
  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 Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
 
  the effect of accounting pronouncements issued periodically by standard setting bodies; and
 
  other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.

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THE SOUTHERN COMPANY AND
SUBSIDIARY COMPANIES

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)     (in millions)  
Operating Revenues:
                               
Retail revenues
  $ 4,693     $ 4,573     $ 11,931     $ 11,603  
Wholesale revenues
    557       566       1,513       1,581  
Other electric revenues
    161       160       464       438  
Other revenues
    17       21       53       63  
 
                       
Total operating revenues
    5,428       5,320       13,961       13,685  
 
                       
Operating Expenses:
                               
Fuel
    1,908       1,970       5,057       5,244  
Purchased power
    215       209       460       464  
Other operations and maintenance
    983       1,019       2,837       2,846  
Depreciation and amortization
    431       427       1,279       1,137  
Taxes other than income taxes
    239       236       686       662  
 
                       
Total operating expenses
    3,776       3,861       10,319       10,353  
 
                       
Operating Income
    1,652       1,459       3,642       3,332  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    42       45       113       140  
Interest expense, net of amounts capitalized
    (217 )     (225 )     (638 )     (666 )
Other income (expense), net
    (1 )     (3 )     (3 )     (10 )
 
                       
Total other income and (expense)
    (176 )     (183 )     (528 )     (536 )
 
                       
Earnings Before Income Taxes
    1,476       1,276       3,114       2,796  
Income taxes
    543       442       1,123       925  
 
                       
Consolidated Net Income
    933       834       1,991       1,871  
Dividends on Preferred and Preference Stock of Subsidiaries
    17       17       49       49  
 
                       
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
  $ 916     $ 817     $ 1,942     $ 1,822  
 
                       
Common Stock Data:
                               
Earnings per share (EPS) -
                               
Basic EPS
  $ 1.07     $ 0.98     $ 2.27     $ 2.20  
Diluted EPS
  $ 1.06     $ 0.97     $ 2.26     $ 2.19  
Average number of shares of common stock outstanding (in millions)
                               
Basic
    860       836       854       829  
Diluted
    868       842       861       833  
Cash dividends paid per share of common stock
  $ 0.4725     $ 0.4550     $ 1.4000     $ 1.3475  
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Consolidated net income
  $ 1,991     $ 1,871  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    1,530       1,377  
Deferred income taxes
    914       573  
Deferred revenues
    (2 )     (77 )
Allowance for equity funds used during construction
    (113 )     (140 )
Pension, postretirement, and other employee benefits
    (1 )     52  
Stock based compensation expense
    35       28  
Generation construction screening costs
          (51 )
Other, net
    13       (1 )
Changes in certain current assets and liabilities —
               
-Receivables
    (118 )     (319 )
-Fossil fuel stock
    229       220  
-Other current assets
    (45 )     (59 )
-Accounts payable
    (155 )     (82 )
-Accrued taxes
    440       118  
-Accrued compensation
    (96 )     93  
-Other current liabilities
    (24 )     (76 )
 
           
Net cash provided from operating activities
    4,598       3,527  
 
           
Investing Activities:
               
Property additions
    (3,115 )     (2,894 )
Distribution of restricted cash
    61       25  
Nuclear decommissioning trust fund purchases
    (1,946 )     (696 )
Nuclear decommissioning trust fund sales
    1,942       672  
Proceeds from property sales
    21       7  
Cost of removal, net of salvage
    (90 )     (84 )
Change in construction payables
    137       (84 )
Other investing activities
    92       48  
 
           
Net cash used for investing activities
    (2,898 )     (3,006 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (1,160 )     (289 )
Proceeds —
               
Long-term debt issuances
    3,144       2,796  
Common stock issuances
    620       610  
Redemptions —
               
Long-term debt
    (1,987 )     (1,871 )
Payment of common stock dividends
    (1,193 )     (1,114 )
Payment of dividends on preferred and preference stock of subsidiaries
    (49 )     (49 )
Other financing activities
    (6 )     (35 )
 
           
Net cash provided from (used for) financing activities
    (631 )     48  
 
           
Net Change in Cash and Cash Equivalents
    1,069       569  
Cash and Cash Equivalents at Beginning of Period
    447       690  
 
           
Cash and Cash Equivalents at End of Period
  $ 1,516     $ 1,259  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $54 and $61 capitalized for 2011 and 2010, respectively)
  $ 369     $ 589  
Income taxes (net of refunds)
    (358 )     278  
Noncash transactions — accrued property additions at end of period
    541       361  
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 1,516     $ 447  
Restricted cash and cash equivalents
    9       68  
Receivables —
               
Customer accounts receivable
    1,401       1,140  
Unbilled revenues
    449       420  
Under recovered regulatory clause revenues
    210       209  
Other accounts and notes receivable
    250       285  
Accumulated provision for uncollectible accounts
    (30 )     (25 )
Fossil fuel stock, at average cost
    1,076       1,308  
Materials and supplies, at average cost
    854       827  
Vacation pay
    150       151  
Prepaid expenses
    319       784  
Other regulatory assets, current
    191       210  
Other current assets
    100       59  
 
           
Total current assets
    6,495       5,883  
 
           
Property, Plant, and Equipment:
               
In service
    58,079       56,731  
Less accumulated depreciation
    20,891       20,174  
 
           
Plant in service, net of depreciation
    37,188       36,557  
Other utility plant, net
    57        
Nuclear fuel, at amortized cost
    743       670  
Construction work in progress
    5,809       4,775  
 
           
Total property, plant, and equipment
    43,797       42,002  
 
           
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,159       1,370  
Leveraged leases
    641       624  
Miscellaneous property and investments
    256       277  
 
           
Total other property and investments
    2,056       2,271  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,361       1,280  
Prepaid pension costs
    137       88  
Unamortized debt issuance expense
    163       178  
Unamortized loss on reacquired debt
    283       274  
Deferred under recovered regulatory clause revenues
    64       218  
Other regulatory assets, deferred
    2,496       2,402  
Other deferred charges and assets
    491       436  
 
           
Total deferred charges and other assets
    4,995       4,876  
 
           
Total Assets
  $ 57,343     $ 55,032  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Liabilities and Stockholders’ Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $ 1,891     $ 1,301  
Notes payable
    137       1,297  
Accounts payable
    1,355       1,275  
Customer deposits
    340       332  
Accrued taxes —
               
Accrued income taxes
    46       8  
Unrecognized tax benefits
    22       187  
Other accrued taxes
    458       440  
Accrued interest
    245       225  
Accrued vacation pay
    191       194  
Accrued compensation
    349       438  
Liabilities from risk management activities
    136       152  
Other regulatory liabilities, current
    107       88  
Other current liabilities
    380       535  
 
           
Total current liabilities
    5,657       6,472  
 
           
Long-term Debt
    18,733       18,154  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    8,613       7,554  
Deferred credits related to income taxes
    223       235  
Accumulated deferred investment tax credits
    579       509  
Employee benefit obligations
    1,608       1,580  
Asset retirement obligations
    1,307       1,257  
Other cost of removal obligations
    1,170       1,158  
Other regulatory liabilities, deferred
    255       312  
Other deferred credits and liabilities
    483       517  
 
           
Total deferred credits and other liabilities
    14,238       13,122  
 
           
Total Liabilities
    38,628       37,748  
 
           
Redeemable Preferred Stock of Subsidiaries
    375       375  
 
           
Stockholders’ Equity:
               
Common Stockholders’ Equity:
               
Common stock, par value $5 per share —
               
Authorized — 1.5 billion shares
               
Issued — September 30, 2011: 862 million shares
               
— December 31, 2010: 844 million shares
               
Treasury — September 30, 2011: 0.5 million shares
               
— December 31, 2010: 0.5 million shares
               
Par value
    4,312       4,219  
Paid-in capital
    4,302       3,702  
Treasury, at cost
    (16 )     (15 )
Retained earnings
    9,116       8,366  
Accumulated other comprehensive loss
    (81 )     (70 )
 
           
Total Common Stockholders’ Equity
    17,633       16,202  
 
           
Preferred and Preference Stock of Subsidiaries
    707       707  
 
           
Total Stockholders’ Equity
    18,340       16,909  
 
           
Total Liabilities and Stockholders’ Equity
  $ 57,343     $ 55,032  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)     (in millions)  
Consolidated Net Income
  $ 933     $ 834     $ 1,991     $ 1,871  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(10), $-, $(8), and $-, respectively
    (17 )     2       (14 )     1  
Reclassification adjustment for amounts included in net income, net of tax of $2, $4, $4, and $10, respectively
    3       3       6       14  
Marketable securities:
                               
Change in fair value, net of tax of $(2), $-, $(1) and $-, respectively
    (5 )     (3 )     (3 )      
Pension and other post retirement benefit plans:
                               
Reclassification adjustment for amounts included in net income, net of tax of $2, $1, $2, and $1, respectively
                      1  
 
                       
Total other comprehensive income (loss)
    (19 )     2       (11 )     16  
 
                       
Dividends on preferred and preference stock of subsidiaries
    (17 )     (17 )     (49 )     (49 )
 
                       
Comprehensive Income
  $ 897     $ 819     $ 1,931     $ 1,838  
 
                       
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010
OVERVIEW
Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the traditional operating companies — Alabama Power, Georgia Power, Gulf Power, and Mississippi Power — and Southern Power. The 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. Southern Company’s other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESS — The Southern Company System — “Traditional Operating Companies,” “Southern Power,” and “Other Businesses” in Item 1 of the Form 10-K.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Southern Company in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$99   12.1   $120   6.6
 
Southern Company’s third quarter 2011 net income after dividends on preferred and preference stock of subsidiaries was $916 million ($1.07 per share) compared to $817 million ($0.98 per share) for the third quarter 2010. The net income increase for the third quarter 2011 when compared to the corresponding period in 2010 was primarily the result of increases in retail base revenues at Georgia Power as authorized under the 2010 ARP and the NCCR tariff and a decrease in other operations and maintenance expenses. The net income increase for third quarter 2011 was partially offset by decreases in revenues due to relatively cooler weather primarily in the month of September compared to the third quarter 2010.
Southern Company’s year-to-date 2011 net income after dividends on preferred and preference stock of subsidiaries was $1.94 billion ($2.27 per share) compared to $1.82 billion ($2.20 per share) for year-to-date 2010. The net income increase for year-to-date 2011 when compared to the corresponding period in 2010 was primarily the result of increases in retail base revenues at Georgia Power as authorized under the 2010 ARP and the NCCR tariff and increases in energy and capacity revenues at Southern Power. The net income increase for year-to-date 2011 was partially offset by a decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, decreases in revenues due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010, a decrease in wholesale revenues primarily at Alabama Power, and an increase in depreciation on additional plant in service related to environmental, transmission, and distribution projects.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$120   2.6   $328   2.8
 
In the third quarter 2011, retail revenues were $4.69 billion compared to $4.57 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $11.93 billion compared to $11.60 billion for the corresponding period in 2010.
Details of the change to retail revenues follow:
                                 
    Third Quarter   Year-to-Date
    2011   2011
    (in millions)   (% change)   (in millions)   (% change)
Retail — prior year
  $ 4,573             $ 11,603          
Estimated change in —
                               
Rates and pricing
    227       5.0       593       5.1  
Sales growth (decline)
    9       0.2       25       0.2  
Weather
    (93 )     (2.0 )     (170 )     (1.5 )
Fuel and other cost recovery
    (23 )     (0.5 )     (120 )     (1.0 )
 
Retail – current year
  $ 4,693       2.7 %   $ 11,931       2.8 %
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 primarily due to increases in Georgia Power’s retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011. Also contributing to these increases were revenues associated with Alabama Power’s Rate CNP Environmental due to completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.
Revenues attributable to changes in sales increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to increases in weather-adjusted retail KWH sales of 0.5% and 1.1%, respectively. For the third quarter 2011, weather-adjusted residential KWH sales decreased 0.3%, weather-adjusted commercial KWH sales remained flat, and weather-adjusted industrial KWH sales increased 2.0%. For year-to-date 2011, weather-adjusted residential KWH sales decreased 0.1%, weather-adjusted commercial KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales increased 3.9%. Increased demand in the primary metals, petroleum refining, fabricated metals, and pipelines sectors were the main contributors to the increases in weather-adjusted industrial KWH sales for the third quarter and year-to-date 2011.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.
Fuel and other cost recovery revenues decreased $23 million in the third quarter 2011 and $120 million for year-to-date 2011 when compared to the corresponding periods in 2010. 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 costs, and do not affect net income.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(9)   (1.6)   $(68)   (4.3)
 
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 fuel prices, the market prices of wholesale energy compared to the Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and the availability of the Southern Company 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 variable cost to produce the energy.
In the third quarter 2011, wholesale revenues were $557 million compared to $566 million for the corresponding period in 2010, reflecting a $15 million decrease in energy revenues and a $6 million increase in capacity revenues. The decrease was primarily due to less favorable weather in the third quarter 2011 and lower energy and capacity revenues associated with the expiration of PPAs in December 2010 at Southern Power. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in December 2010 and January 2011.
For year-to-date 2011, wholesale revenues were $1.51 billion compared to $1.58 billion for the corresponding period in 2010, reflecting a $48 million decrease in energy revenues and a $20 million decrease in capacity revenues. The decrease was primarily related to a decrease in wholesale revenues at Alabama Power due to the expiration of long-term unit power sales contracts in May 2010 and the capacity subject to those contracts being made available for retail service starting in June 2010, as well as lower energy and capacity revenues associated with the expiration of PPAs in December 2010 at Southern Power. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in June, July, and December 2010 and January 2011.
Other Electric Revenues
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$1   0.6   $26   5.9
 
In the third quarter 2011, other electric revenues were $161 million compared to $160 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material. For year-to-date 2011, other electric revenues were $464 million compared to $438 million for the corresponding period in 2010. The increase was primarily the result of an increase in transmission revenues at Georgia Power.
Other Revenues
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(4)   (19.0)   $(10)   (15.9)
 
In the third quarter 2011, other revenues were $17 million compared to $21 million for the corresponding period in 2010. For year-to-date 2011, other revenues were $53 million compared to $63 million for the corresponding period in 2010. The third quarter and year-to-date 2011 decreases were primarily the result of a decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to continued competition in the industry.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2011   Year-to-Date 2011
    vs.   vs.
    Third Quarter 2010   Year-to-Date 2010
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ (62 )     (3.1 )   $ (187 )     (3.6 )
Purchased power
    6       2.9       (4 )     (0.9 )
                         
Total fuel and purchased power expenses
  $ (56 )           $ (191 )        
                         
 
*   Fuel includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.
Fuel and purchased power expenses for the third quarter 2011 were $2.12 billion compared to $2.18 billion for the corresponding period in 2010. The decrease was primarily the result of a $59 million net decrease in the average cost of fuel and purchased power, slightly offset by a $3 million net increase related to total KWHs generated and purchased. The decrease in the average cost of fuel and purchased power was primarily the result of a 21.7% decrease in the average cost of purchased power, slightly offset by a 1.1% increase in the average cost of fuel per KWH generated.
For year-to-date 2011, fuel and purchased power expenses were $5.52 billion compared to $5.71 billion for the corresponding period in 2010. The decrease was primarily the result of a $143 million net decrease related to total KWHs generated and purchased and a $48 million decrease in the average cost of fuel and purchased power. The net decrease related to total KWHs generated and purchased resulted primarily from lower customer demand. The decrease in the average cost of fuel and purchased power resulted primarily from a 9.6% decrease in the average cost of natural gas per KWH generated, partially offset by a 3.8% increase in the average cost of coal per KWH generated.
Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not have a significant effect on net income. See FUTURE EARNINGS POTENTIAL — “State PSC Matters — Retail Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly affect net income.
Details of the Southern Company system’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter                           Percent
Average Cost   2011   2010   Percent Change   Year-to-Date 2011   Year-to-Date 2010   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    3.59       3.55       1.1       3.52       3.55       (0.9 )
Purchased power
    6.29       8.03       (21.7 )     7.06       7.13       (1.0 )
 
Energy purchases will vary depending on demand for energy within the Southern Company system service area, the market cost of available energy as compared to the cost of Southern Company system-generated energy, and the availability of Southern Company system generation.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(36)   (3.5)   $(9)   (0.3)
 
In the third quarter 2011, other operations and maintenance expenses were $983 million compared to $1.02 billion for the corresponding period in 2010. The decrease was primarily the result of an additional accrual in the third quarter 2010 of $40 million to the NDR at Alabama Power and reductions in overhead line costs at Alabama Power due to storm restoration efforts. The decrease was partially offset by increases in routine transmission and distribution expenses and customer service related costs.
For year-to-date 2011, other operations and maintenance expenses were $2.84 billion compared to $2.85 billion for the corresponding period in 2010. The decrease was primarily the result of a $53 million decrease in transmission and distribution costs mainly due to an additional accrual in the third quarter 2010 of $40 million to the NDR at Alabama Power and reductions in overhead line costs at Alabama Power due to storm restoration efforts, partially offset by an increase in overhead line maintenance at Georgia Power. Also contributing to the decrease was a $20 million reduction in administrative and general costs. The decrease was partially offset by a $33 million increase in commodity and labor costs, a $17 million increase in scheduled outage and maintenance costs, and a $12 million increase in customer service related costs.
In August 2010, the Alabama PSC approved a change to Alabama Power’s nuclear maintenance outage accounting process associated with routine refueling activities. As a result, Alabama Power will not recognize any nuclear maintenance outage expenses in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Nuclear Outage Accounting Order” of Southern Company in Item 7 of the Form 10-K for additional information.
Depreciation and Amortization
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$4   0.9   $142   12.5
 
In the third quarter 2011, depreciation and amortization was $431 million compared to $427 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, depreciation and amortization was $1.28 billion compared to $1.14 billion for the corresponding period in 2010. The increase was primarily the result of a $94 million decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC and additional depreciation on plant in service related to environmental, transmission, and distribution projects.
See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information on the other cost of removal regulatory liability.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$3   1.3   $24   3.6
 
In the third quarter 2011, taxes other than income taxes were $239 million compared to $236 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, taxes other than income taxes were $686 million compared to $662 million for the corresponding period in 2010. The year-to-date 2011 increase was primarily the result of increases in property taxes and franchise fees.
Allowance for Equity Funds Used During Construction
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(3)   (6.7)   $(27)   (19.3)
 
In the third quarter 2011, AFUDC equity was $42 million compared to $45 million for the corresponding period in 2010. The decrease when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, AFUDC equity was $113 million compared to $140 million for the corresponding period in 2010. The decrease was primarily due to the inclusion of Georgia Power’s Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011 which reduced the amount of AFUDC capitalized and the completion of construction projects related to environmental mandates at Alabama Power. The decrease was partially offset by construction work in progress related to Mississippi Power’s Kemper IGCC which began construction in June 2010.
See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” herein for additional information.
Interest Expense, Net of Amounts Capitalized
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(8)   (3.6)   $(28)   (4.2)
 
In the third quarter 2011, interest expense, net of amounts capitalized was $217 million compared to $225 million for the corresponding period in 2010. The decrease was primarily due to lower interest expense on variable rate pollution control bonds at Georgia Power.
For year-to-date 2011, interest expense, net of amounts capitalized was $638 million compared to $666 million for the corresponding period in 2010. The decrease was primarily due to a reduction of $23 million in interest expense at Georgia Power related to the settlement of tax litigation with the Georgia Department of Revenue (DOR). See Note (B) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$101   22.9   $198   21.4
 
In the third quarter 2011, income taxes were $543 million compared to $442 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings and an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.
For year-to-date 2011, income taxes were $1.12 billion compared to $925 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings, a decrease in the first quarter 2010 in uncertain tax positions at Georgia Power related to state income tax credits, an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, and a reduction in AFUDC equity, which is non-taxable.
See Notes (B) and (G) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the 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 available generating capacity, 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.
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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Southern Company has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Southern Company in Item 7 of the Form 10-K for additional information regarding the proposed coal combustion byproducts rule. Although its analysis is preliminary,

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company estimates that the aggregate capital costs to the traditional operating companies for compliance with these rules could range from $13 billion to $18 billion through 2020 if the rules are adopted as proposed. Included in this amount is $686 million of estimated expenditures included in the 2011-2013 base level capital budgets of Southern Company subsidiaries described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein for additional information. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Southern Company’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit. The ultimate outcome of this matter cannot be determined at this time.
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — New York Case” of Southern Company in Item 7 and Note 3 of the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Southern Company in Item 7 and Note 3 of the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies (including Alabama Power, Georgia Power, Gulf Power, and Southern Power) and includes many of the same defendants that were involved in the earlier case. Southern Company believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of air quality.
On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of the facilities of Southern Company’s subsidiaries which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.
In April 2010, the EPA proposed an Industrial Boiler 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 published the final rule on March 21, 2011 and, at the same time, issued a notice of intent to reconsider the final rule to allow for additional public review and comment. The EPA has announced plans to finalize the rule by April 30, 2012. The effect of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time. On October 18, 2011, the Georgia PSC approved Georgia Power’s request to further delay the decision to convert Plant Mitchell Unit 3 from coal to biomass for two to four years, until there is greater clarity regarding the Industrial Boiler MACT rule and other proposed and recently adopted regulations. Georgia Power will file semi-annual construction monitoring reports on March 1 and August 15 throughout the delay period.
In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. On April 6, 2011, the EPA attempted to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s

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attempted rescission pending judicial review. The EPA’s decision became effective May 6, 2011 and the court denied Alabama Power’s requested stay on May 12, 2011. Unless the court resolves Alabama Power’s appeal in its favor, the EPA’s rescission will continue to affect Alabama Power’s operations. The EPA’s rescission has affected unit availability and increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.
On June 23, 2011, the EPA published its determination that the 20-county area within metropolitan Atlanta has air quality which attains the 1997 eight-hour ozone air quality standard. In March 2008, the EPA adopted a more stringent eight-hour ozone air quality standard, which it began to implement in September 2011. The 2008 standard is expected to result in designation of new nonattainment areas within the Southern Company system service territory and could result in additional required reductions in nitrogen oxide emissions. The ultimate outcome of this matter cannot be determined at this time.
On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. Each of the states within the Southern Company system service area is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program, and the States of Alabama, Georgia, North Carolina, and Texas are subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for each state, and the effect on each of the traditional operating companies will vary. The rule could have significant effects on the traditional operating companies, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including the traditional operating companies and Southern Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.
On March 22, 2011, the Board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule, which is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. On June 29, 2011, the modifications were approved and the compliance dates for certain of Georgia Power’s coal-fired generating units were changed as follows:
         
 
  Branch 1   December 31, 2013
 
  Branch 2   October 1, 2013
 
  Branch 3   October 1, 2015
 
  Branch 4   December 31, 2015
See “State PSC Matters — Georgia Power Retail Regulatory Matters — 2011 Integrated Resource Plan Update” herein for additional information.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn

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through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Southern Company’s subsidiaries’ existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of the facilities of Southern Company’s subsidiaries may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
State PSC Matters
Retail 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 have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. 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 $260 million at September 30, 2011. Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2011, had a total over recovered fuel balance of approximately $41 million. At December 31, 2010, total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power were approximately $420 million and Mississippi Power had a total over recovered fuel balance of $55 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on Southern Company’s revenues or net income, but does impact annual cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.
On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Alabama Power Retail Regulatory Matters
Environmental Accounting Order
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — General” of Southern Company in Item 7 of the Form 10-K for additional information regarding environmental regulations. Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Rate Adjustments
See BUSINESS — “Rate Matters — Rate Structure and Cost Recovery Plans” of Southern Company in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Rate RSE” and “PSC Matters — Alabama Power — Natural Disaster Reserve” of Southern Company in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.
In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.
Natural Disaster Reserve
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Natural Disaster Reserve” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Alabama Power — Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information.
During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.
At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.
In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.
Georgia Power Retail Regulatory Matters
2011 Integrated Resource Plan Update
See “Environmental Matters — Air Quality” and “— Water Quality” herein and BUSINESS — “Rate Matters — Integrated Resource Planning” of Southern Company in Item 1, MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “— Water Quality,” and “— Coal Combustion Byproducts” of Southern Company in Item 7, and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility

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MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; and the 2010 ARP.
On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.
Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s 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. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s financial statements.
The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.
Storm Damage Recovery
During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2011, the balance in the regulatory asset related to storm damage was $45 million. As a result of this regulatory treatment, the costs related to the storms are not expected to have a material impact on Southern Company’s financial statements. See Note 1 to the financial statements of Southern Company under “Storm Damage Reserves” in Item 8 of the Form 10-K for additional information.
Gulf Power Retail Regulatory Matters
Retail Base Rate Case
On July 8, 2011, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates to the extent necessary to generate additional gross annual revenues in the amount of $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012.

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On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.
The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
Legislation
On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. 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 June 10, 2011, Georgia Power and the Georgia DOR agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, for additional information.
Bonus Depreciation
In September 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, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (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 will have a positive impact on the future cash flows of Southern Company through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Southern Company estimates the potential increased cash flow for 2011 to be between approximately $500 million and $600 million. The ultimate outcome of this matter cannot be determined at this time.
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, biomass, and potentially solar units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC facility 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 of

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Southern Company under “Construction Program” in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company 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” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” and “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein for additional information.
On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. While the Southern Company system will continue to monitor this situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of the existing nuclear generating units of Alabama Power and Georgia Power.
The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. The task force report supported completion of the certification of the AP1000 reactor design being used at Plant Vogtle Units 3 and 4, noting that the design has many of the features necessary to address the task force’s recommendations.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
Investments in 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. Southern 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. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.
The recent financial and operational performance of one of Southern Company’s lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the asset. Southern Company will continue to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. While there are strategic options that Southern Company may pursue to recover its investment in the leveraged lease, the potential impairment loss that would be incurred if there is an abandonment of the project is expected to be approximately $80 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

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Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as 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, 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 or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at September 30, 2011. 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.
Net cash provided from operating activities totaled $4.60 billion for the first nine months of 2011, an increase of $1.07 billion from the corresponding period in 2010. Significant changes in operating cash flow for the first nine months of 2011 as compared to the corresponding period in 2010 include an increase in net income as previously discussed. Also contributing to the increase was an increase in deferred income taxes related to bonus depreciation and an increase in accrued income taxes primarily due to the timing of tax payments. Net cash used for investing activities totaled $2.90 billion for the first nine months of 2011, a decrease of $108 million from the corresponding period in 2010 due to timing of capital expenditures. Net cash used for financing activities totaled $631 million for the first nine months of 2011, compared to $48 million provided from financing activities in the corresponding period in 2010. This change was primarily due to a decrease in notes payable and redemptions of long-term debt, partially offset by long-term debt issuances. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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Significant balance sheet changes for the first nine months of 2011 include an increase in cash of $1.07 billion due to increased cash collection from operations during the summer months, higher cash balances at Alabama Power, and an increase of $1.79 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 significant changes include a decrease in notes payable of $1.16 billion and an increase in equity of $1.43 billion.
The market price of Southern Company’s common stock at September 30, 2011 was $42.37 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.46 per share, representing a market-to-book ratio of 207%, compared to $38.23, $19.21, and 199%, respectively, at the end of 2010. The dividend for the third quarter 2011 was $0.4725 per share compared to $0.455 per share in the third quarter 2010.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for the construction programs of its subsidiaries and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $1.89 billion will be required through September 30, 2012 to fund maturities of long-term debt.
The construction programs of Southern Company’s subsidiaries are 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, Southern Company 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. If the EPA’s proposed Utility MACT rule is finalized as proposed, Southern Company estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. 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.
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 Southern Company’s 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 Company’s 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. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In June 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 the construction of 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 Power’s 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 $3.46 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 licenses for Plant Vogtle Units 3 and 4 from the 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. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power.
Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.
At September 30, 2011, Southern Company and its subsidiaries had approximately $1.5 billion of cash and cash equivalents and approximately $5.13 billion of unused committed credit arrangements with banks, of which $96 million expire in 2011, $316 million expire in 2012, $60 million expire in 2013, $860 million expire in 2014, and $3.80 billion expire in 2016. Of the credit arrangements expiring on or before September 30, 2012, $41 million contain provisions allowing two-year term loans executable at expiration and $216 million contain provisions allowing one-year term loans executable at expiration. Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014. At September 30, 2011, approximately $1.8 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein 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 September 30, 2011, the Southern Company system had approximately $132 million of short-term borrowings outstanding, comprised of commercial paper, with a weighted average interest rate of 0.27% per annum. During the third quarter 2011, Southern Company had an average of $510 million of short-term borrowings outstanding with a weighted average interest rate of 0.29% per annum and the maximum amount outstanding was $903 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Off-Balance Sheet Financing Arrangements
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information relating to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel (Facility).
Mississippi Power was required to provide notice of its intent to either renew the lease or purchase the Facility by July 22, 2011. On July 20, 2011, Mississippi Power provided notice to the lessor of its intent to purchase the Facility. Mississippi Power’s right to purchase the Facility was approved by the Mississippi PSC in its order dated January 7, 1998, as amended on February 19, 1999, which granted Mississippi Power a Certificate of Public Convenience and Necessity for the Facility.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On October 20, 2011, Mississippi Power purchased the Facility for approximately $85 million in cash and the assumption of debt obligations of the lessor related to the Facility, which mature in 2021, have a face value of $270 million and a fixed stated interest rate of 7.13%, and are secured by the Facility and certain personal property, accounts, and proceeds related thereto. Accounting rules require that the Facility be reflected on Southern Company’s financial statements at the time of the purchase at the fair value of the consideration rendered. Based on interest rates as of October 20, 2011, the fair value of the debt assumed was approximately $346 million. Accordingly, the Facility will be reflected in Southern Company’s financial statements at approximately $431 million. Mississippi Power intends to maintain its traditional capital structure by adding equity to support the additional debt.
In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. On November 2, 2011, Mississippi Power filed a request with the FERC seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase of the Facility (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment. At the conclusion of the proposed deferral period in 2021, the accumulated deferred balance will be amortized into wholesale rates over the remaining life of the Facility. The ultimate outcome of these matters cannot be determined at this time.
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 September 30, 2011, 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 $606 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.8 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. Southern Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, Southern Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Company’s policies in areas such as counterparty exposure and risk management practices. Southern Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
electricity prices, the traditional operating companies enter into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2011 were as follows:
                 
    Third Quarter   Year-to-Date
    2011   2011
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (136 )   $ (196 )
Contracts realized or settled
    51       137  
Current period changes(a)
    (66 )     (92 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (151 )   $ (151 )
 
 
(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 three and nine months ended September 30, 2011 was a decrease of $15 million and an increase of $45 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Southern Company had a net hedge volume of 160 million mmBtu with a weighted average contract cost approximately $1.10 per mmBtu above market prices, compared to 154 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.97 per mmBtu above market prices and compared to 149 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.35 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.
The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
                 
Asset (Liability) Derivatives   September 30, 2011   December 31, 2010
    (in millions)
Regulatory hedges
  $ (147 )   $ (193 )
Cash flow hedges
          (1 )
Not designated
    (4 )     (2 )
 
Total fair value
  $ (151 )   $ (196 )
 
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 used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in income were $(1) million and $(2) million, respectively, for the three and nine months ended September 30, 2011 and will continue to be marked to market until the settlement date. For the three and nine months ended September 30, 2010, the total net unrealized pre-tax gains (losses) recognized in the statements of income were $(4) million and $(2) million, respectively.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:
                                 
            September 30, 2011        
            Fair Value Measurements        
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (151 )     (117 )     (33 )     (1 )
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (151 )   $ (117 )   $ (33 )   $ (1 )
 
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. 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.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Southern Company in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the first nine months of 2011, Southern Company issued approximately 18.6 million shares of common stock for $620 million through the Southern Investment Plan and employee and director stock plans. The proceeds were primarily used for general corporate purposes, including the investment by Southern Company in its subsidiaries, and to repay short-term indebtedness. While Southern Company continues to issue additional equity through its employee and director equity compensation plans, Southern Company is not currently issuing additional shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by the independent plan administrators.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following table outlines the debt financing activities for Southern Company, the traditional operating companies, and Southern Power for the first nine months of 2011:
                                                 
            Senior Note   Pollution
Control Bond
  Pollution
Control Bond
  Other Long-   Other Long-
Term Debt
    Senior Note   Redemptions   Issuances and   Redemptions   Term Debt   Redemptions
Company   Issuances   and Maturities   Remarketings(*)   and Maturities   Issuances   and Maturities
                    (in millions)                
Southern Company
  $ 500     $     $     $     $     $  
Alabama Power
    700       650             4              
Georgia Power
    550       277       604       286       250       509  
Gulf Power
    125                               110  
Mississippi Power
                            115       130  
Southern Power
    300                               3  
 
Total
  $ 2,175     $ 927     $ 604     $ 290     $ 365     $ 752  
 
 
(*)   Includes the remarketing by Georgia Power of pollution control bonds that had been purchased and held by Georgia Power.
In August 2011, Southern Company issued $500 million aggregate principal amount of Series 2011A 1.95% Senior Notes due September 1, 2016. The net proceeds from the sale of the Series 2011A Senior Notes were used to repay a portion of Southern Company’s outstanding short-term indebtedness and for other general corporate purposes.
Southern Company’s subsidiaries used the proceeds of the debt issuances shown in the table above for the redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.
In March 2011, Alabama Power settled $200 million of interest rate hedges related to its Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.
In August 2011, 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 $300 million.
In September 2011, Mississippi Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $600 million.
Subsequent to September 30, 2011, Alabama Power announced the redemption that will occur on November 14, 2011 of approximately $100 million aggregate principal amount of its Series EE 5.75% Senior Notes due January 15, 2036.
Subsequent to September 30, 2011, Georgia Power announced the redemption that will occur on November 21, 2011 of $53 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1999.
Subsequent to September 30, 2011, Mississippi Power issued $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016 and $150 million aggregate principal amount of Series 2011B 4.75% Senior Notes due October 15, 2041. Mississippi Power also settled hedges totaling $150 million related to the Series 2011A issuance at a gain of approximately $1.4 million. This gain will be amortized to interest expense, in earnings, over five years. Mississippi Power settled hedges totaling $150 million related to the Series 2011B issuance at a loss of approximately $0.54 million. This loss will be amortized to interest expense, in earnings, over 10 years.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to September 30, 2011, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 21, 2021, issued for the benefit of the lessor as described under “Off-Balance Sheet Financing Arrangements” herein. These bonds are secured by the Facility and certain personal property, accounts, and proceeds related thereto.
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.

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PART I
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for each registrant and Note 1 to the financial statements of each registrant under “Financial Instruments,” Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
     (a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this quarterly 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 company’s management, including the Chief Executive Officer and the 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.
     (b) Changes in internal controls.
There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s 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 third quarter 2011 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

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ALABAMA POWER COMPANY

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ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)     (in millions)  
Operating Revenues:
                               
Retail revenues
  $ 1,489     $ 1,527     $ 3,859     $ 3,925  
Wholesale revenues, non-affiliates
    80       86       218       395  
Wholesale revenues, affiliates
    52       43       202       194  
Other revenues
    50       50       152       149  
 
                       
Total operating revenues
    1,671       1,706       4,431       4,663  
 
                       
Operating Expenses:
                               
Fuel
    512       500       1,335       1,455  
Purchased power, non-affiliates
    34       35       62       66  
Purchased power, affiliates
    49       57       152       161  
Other operations and maintenance
    309       379       896       997  
Depreciation and amortization
    160       153       476       451  
Taxes other than income taxes
    84       85       254       248  
 
                       
Total operating expenses
    1,148       1,209       3,175       3,378  
 
                       
Operating Income
    523       497       1,256       1,285  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    7       9       18       29  
Interest income
    4       4       13       12  
Interest expense, net of amounts capitalized
    (73 )     (76 )     (224 )     (227 )
Other income (expense), net
    (7 )     (7 )     (20 )     (18 )
 
                       
Total other income and (expense)
    (69 )     (70 )     (213 )     (204 )
 
                       
Earnings Before Income Taxes
    454       427       1,043       1,081  
Income taxes
    180       158       407       399  
 
                       
Net Income
    274       269       636       682  
Dividends on Preferred and Preference Stock
    10       10       30       30  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 264     $ 259     $ 606     $ 652  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)       (in millions)  
Net Income After Dividends on Preferred and Preference Stock
  $ 264     $ 259     $ 606     $ 652  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(4), $-, $(3), and $-, respectively
    (8 )           (5 )      
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $(1), and $-, respectively
                (2 )      
 
                       
Total other comprehensive income (loss)
    (8 )           (7 )      
 
                       
Comprehensive Income
  $ 256     $ 259     $ 599     $ 652  
 
                       
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Net income
  $ 636     $ 682  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    562       519  
Deferred income taxes
    350       301  
Allowance for equity funds used during construction
    (18 )     (29 )
Pension, postretirement, and other employee benefits
    (17 )     (9 )
Stock based compensation expense
    5       4  
Other, net
    6       29  
Changes in certain current assets and liabilities —
               
-Receivables
    (74 )     (110 )
-Fossil fuel stock
    75       21  
-Materials and supplies
    (13 )     (10 )
-Other current assets
    (19 )     (34 )
-Accounts payable
    (120 )     (66 )
-Accrued taxes
    215       (48 )
-Accrued compensation
    (35 )     8  
-Other current liabilities
    5       (103 )
 
           
Net cash provided from operating activities
    1,558       1,155  
 
           
Investing Activities:
               
Property additions
    (694 )     (685 )
Distribution of restricted cash from pollution control revenue bonds
    11       18  
Nuclear decommissioning trust fund purchases
    (301 )     (126 )
Nuclear decommissioning trust fund sales
    301       126  
Cost of removal, net of salvage
    (52 )     (26 )
Change in construction payables
    (13 )     (34 )
Other investing activities
    14       (9 )
 
           
Net cash used for investing activities
    (734 )     (736 )
 
           
Financing Activities:
               
Proceeds —
               
Capital contributions from parent company
    10       19  
Senior notes issuances
    700        
Redemptions —
               
Pollution control revenue bonds
    (4 )      
Senior notes
    (650 )      
Payment of preferred and preference stock dividends
    (30 )     (30 )
Payment of common stock dividends
    (415 )     (407 )
Other financing activities
    (13 )     (1 )
 
           
Net cash used for financing activities
    (402 )     (419 )
 
           
Net Change in Cash and Cash Equivalents
    422        
Cash and Cash Equivalents at Beginning of Period
    154       368  
 
           
Cash and Cash Equivalents at End of Period
  $ 576     $ 368  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $7 and $11 capitalized for 2011 and 2010, respectively)
  $ 207     $ 214  
Income taxes (net of refunds)
    (95 )     212  
Noncash transactions — accrued property additions at end of period
    15       39  
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 576     $ 154  
Restricted cash and cash equivalents
    3       18  
Receivables —
               
Customer accounts receivable
    419       362  
Unbilled revenues
    126       153  
Under recovered regulatory clause revenues
    11       5  
Other accounts and notes receivable
    48       35  
Affiliated companies
    47       57  
Accumulated provision for uncollectible accounts
    (10 )     (10 )
Fossil fuel stock, at average cost
    316       391  
Materials and supplies, at average cost
    355       346  
Vacation pay
    55       55  
Prepaid expenses
    77       208  
Other regulatory assets, current
    33       38  
Other current assets
    11       10  
 
           
Total current assets
    2,067       1,822  
 
           
Property, Plant, and Equipment:
               
In service
    20,530       19,966  
Less accumulated provision for depreciation
    7,247       6,931  
 
           
Plant in service, net of depreciation
    13,283       13,035  
Nuclear fuel, at amortized cost
    316       283  
Construction work in progress
    485       547  
 
           
Total property, plant, and equipment
    14,084       13,865  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    62       64  
Nuclear decommissioning trusts, at fair value
    502       552  
Miscellaneous property and investments
    73       71  
 
           
Total other property and investments
    637       687  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    528       488  
Prepaid pension costs
    287       257  
Deferred under recovered regulatory clause revenues
    39       4  
Other regulatory assets, deferred
    680       675  
Other deferred charges and assets
    193       196  
 
           
Total deferred charges and other assets
    1,727       1,620  
 
           
Total Assets
  $ 18,515     $ 17,994  
 
           
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $     $ 200  
Accounts payable —
               
Affiliated
    195       210  
Other
    198       273  
Customer deposits
    85       86  
Accrued taxes —
               
Accrued income taxes
    13       2  
Other accrued taxes
    103       32  
Accrued interest
    71       63  
Accrued vacation pay
    45       45  
Accrued compensation
    73       99  
Liabilities from risk management activities
    24       31  
Over recovered regulatory clause revenues
    25       22  
Other current liabilities
    35       41  
 
           
Total current liabilities
    867       1,104  
 
           
Long-term Debt
    6,232       5,987  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    3,148       2,747  
Deferred credits related to income taxes
    81       85  
Accumulated deferred investment tax credits
    151       157  
Employee benefit obligations
    323       311  
Asset retirement obligations
    544       520  
Other cost of removal obligations
    702       701  
Other regulatory liabilities, deferred
    92       217  
Other deferred credits and liabilities
    92       87  
 
           
Total deferred credits and other liabilities
    5,133       4,825  
 
           
Total Liabilities
    12,232       11,916  
 
           
Redeemable Preferred Stock
    342       342  
 
           
Preference Stock
    343       343  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $40 per share —
               
Authorized - 40,000,000 shares
               
Outstanding - 30,537,500 shares
    1,222       1,222  
Paid-in capital
    2,177       2,156  
Retained earnings
    2,213       2,022  
Accumulated other comprehensive loss
    (14 )     (7 )
 
           
Total common stockholder’s equity
    5,598       5,393  
 
           
Total Liabilities and Stockholder’s Equity
  $ 18,515     $ 17,994  
 
           
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include the 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 costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$5   1.9   $(46)   (7.1)
 
Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2011 was $264 million compared to $259 million for the corresponding period in 2010. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2011 was $606 million compared to $652 million for the corresponding period in 2010. For the third quarter 2011, the increase in net income when compared to the corresponding period in 2010 was not material. The decrease for year-to-date 2011 when compared to the corresponding period in 2010 was primarily due to reductions in wholesale revenues from sales to non-affiliates, relatively cooler weather primarily in the month of September compared to the third quarter 2010, significantly colder weather in the first quarter 2010, an increase in depreciation and amortization, and a reduction in AFUDC equity. The decreases in income were partially offset by a decrease in other operations and maintenance expenses, an increase in revenues under Rate CNP Environmental associated with the completion of construction projects related to environmental projects, and an increase in industrial KWH sales.
Retail Revenues
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$(38)   (2.5)   $(66)   (1.7)
 
In the third quarter 2011, retail revenues were $1.49 billion compared to $1.53 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $3.86 billion compared to $3.93 billion for the corresponding period in 2010.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2011   2011
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 1,527             $ 3,925          
Estimated change in –
                               
Rates and pricing
    3       0.2       49       1.2  
Sales growth (decline)
    19       1.2       23       0.6  
Weather
    (61 )     (4.0 )     (97 )     (2.5 )
Fuel and other cost recovery
    1       0.1       (41 )     (1.0 )
 
Retail – current year
  $ 1,489       (2.5 )%   $ 3,859       (1.7 )%
 
Revenues associated with changes in rates and pricing increased in the third quarter 2011 and year-to-date 2011, when compared to the corresponding periods in 2010, primarily due to increased revenues associated with Rate CNP Environmental. The increase was due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.
Revenues attributable to changes in sales increased in the third quarter 2011 when compared to the corresponding period in 2010. Industrial KWH energy sales increased 3.1% due to an increase in demand resulting from changes in production levels primarily in the primary metals sector. Weather-adjusted residential and commercial KWH energy sales increased 1.3% and 1.2%, respectively, driven by an increase in demand.
Revenues attributable to changes in sales increased year-to-date 2011 when compared to the corresponding period in 2010. Industrial KWH energy sales increased 5.7% due to an increase in demand resulting from changes in production levels primarily in the chemical and primary metals sectors. The decreases in weather-adjusted residential and commercial KWH energy sales were not material.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010. In the third quarter 2011, residential and commercial sales revenues decreased 6.4% and 3.3%, respectively, as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010. For year-to-date 2011, residential and commercial sales revenues decreased 4.5% and 1.5%, respectively, as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.
In the third quarter 2011, the increase in fuel and other cost recovery revenues when compared to the corresponding period in 2010 was not material. Fuel and other cost recovery revenues decreased year-to-date 2011 when compared to the corresponding period in 2010 primarily due to a decrease in fuel costs and a decrease in costs associated with PPAs certificated by the Alabama PSC. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$(6)   (7.0)   $(177)   (44.8)
 
Wholesale revenues from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of Alabama Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.
In the third quarter 2011, wholesale revenues from non-affiliates were $80 million compared to $86 million for the corresponding period in 2010, reflecting a $9 million decrease in revenue from energy sales and a $3 million increase in capacity revenue. The decrease was primarily due to a 9.0% decrease in KWH sales, partially offset by a 2.4% increase in the price of energy.
For year-to-date 2011, wholesale revenues from non-affiliates were $218 million compared to $395 million for the corresponding period in 2010, reflecting a $101 million decrease in revenue from energy sales and a $76 million decrease in capacity revenue. The decrease was primarily due to a 51.3% decrease in KWH sales, partially offset by a 13.3% increase in the price of energy.
In May 2010, the long-term unit power sales contracts expired and the unit power energy sales and capacity revenues ceased. In the third quarter 2011, the revenue reduction when compared to the corresponding period in 2010 was not material. For year-to-date 2011, there was a $178 million revenue reduction when compared to the corresponding period in 2010. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$9   20.9   $8   4.1
 
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the third quarter 2011, wholesale revenues from affiliates were $52 million compared to $43 million for the corresponding period in 2010. The increase was primarily due to a 25.0% increase in KWH sales, partially offset by a 3.1% decrease in price.
For year-to-date 2011, the increase in wholesale revenues from affiliates when compared to the corresponding period in 2010 was not material.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2011   Year-to-Date 2011
    vs.   vs.
    Third Quarter 2010   Year-to-Date 2010
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel *
  $ 12       2.4     $ (120 )     (8.2 )
Purchased power – non-affiliates
    (1 )     (2.9 )     (4 )     (6.1 )
Purchased power – affiliates
    (8 )     (14.0 )     (9 )     (5.6 )
                   
Total fuel and purchased power expenses
  $ 3             $ (133 )        
                     
 
*   Fuel includes fuel purchased by Alabama Power 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 the third quarter 2011, the increase in total fuel and purchased power expenses when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, total fuel and purchased power expenses were $1.55 billion compared to $1.68 billion for the corresponding period in 2010. The decrease was primarily due to a $78 million decrease related to lower KWHs generated as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010 and a $42 million decrease in the cost of fuel and the average cost of purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Rate ECR. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.
Details of Alabama Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter   Percent   Year-to-Date   Year-to-Date   Percent
Average Cost   2011   2010   Change   2011   2010   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel *
    2.89       2.72       6.3       2.75       2.78       (1.1 )
Purchased power
    6.97       7.11       (2.0 )     6.14       6.83       (10.1 )
 
 
*   KWHs generated by hydro are excluded from the average cost of fuel.
In the third quarter 2011, the increase in fuel expense when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, fuel expense was $1.34 billion compared to $1.46 billion for the corresponding period in 2010. The $120 million decrease was due to a 12.3% decrease in KWHs generated by coal and an 11.7% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements. The decreases were partially offset by a 5.4% increase in the average cost of coal.
Non-Affiliates
The decreases for the third quarter and year-to-date 2011 in purchased power expense from non-affiliates, when compared to the corresponding periods in 2010, were not material.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Affiliates
In the third quarter 2011, purchased power expense from affiliates was $49 million compared to $57 million for the corresponding period in 2010. The decrease was related to a 14.8% decrease in the average cost per KWH.
For year-to-date 2011, purchased power expense from affiliates was $152 million compared to $161 million for the corresponding period in 2010. The decrease was related to a 25.5% decrease in the average cost per KWH, partially offset by a 12.1% increase in the amount of energy purchased.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$(70)   (18.5)   $(101)   (10.1)
 
In the third quarter 2011, other operations and maintenance expenses were $309 million compared to $379 million for the corresponding period in 2010. Distribution and transmission expenses decreased $57 million primarily due to an additional accrual of $40 million to the NDR in the third quarter 2010 and reductions in overhead line costs due to storm restoration efforts. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Natural Disaster Reserve” herein for additional information. Administrative and general expenses decreased $5 million primarily related to decreases in injuries and damages expenses and affiliated service companies’ expenses. Nuclear production expenses decreased $5 million primarily due to a change to the nuclear maintenance outage accounting process associated with the routine refueling activities, as approved by the Alabama PSC in August 2010. As a result, no nuclear maintenance outage expenses will be recognized in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Nuclear Outage Accounting Order” of Alabama Power in Item 7 of the Form 10-K for additional information. In addition, the decrease in nuclear production expenses was partially offset by an increase in operations costs related to increases in labor.
For year-to-date 2011, other operations and maintenance expenses were $896 million compared to $997 million for the corresponding period in 2010. Distribution and transmission expenses decreased $69 million primarily due to an additional accrual of $40 million to the NDR in 2010 and reductions in overhead line costs due to storm restoration efforts. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Natural Disaster Reserve” herein for additional information. Administrative and general expenses decreased $17 million primarily related to decreases in injuries and damages expenses and affiliated service companies’ expenses. Nuclear production expenses decreased $16 million primarily due to a change to the nuclear maintenance outage accounting process, as discussed above, partially offset by an increase in operations costs related to increases in labor.
Depreciation and Amortization
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$7   4.6   $25   5.5
 
In the third quarter 2011, depreciation and amortization was $160 million compared to $153 million for the corresponding period in 2010. The increase was due to additions of property, plant, and equipment related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2011, depreciation and amortization was $476 million compared to $451 million for the corresponding period in 2010. The increase was due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2)   (22.2)   $(11)   (37.9)
 
In the third quarter 2011, the decrease in AFUDC equity when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, AFUDC equity was $18 million compared to $29 million for the corresponding period in 2010. The decrease was primarily due to the completion of construction projects related to environmental mandates at Plants Barry, Gaston, and Miller.
Income Taxes
             
Third Quarter 2011 vs. Third Quarter 2010         Year-to-Date 2011 vs. Year-to-Date 2010          
 
(change in millions)   (% change)   (change in millions)   (% change)
$22   13.9   $8   2.0
 
In the third quarter 2011, income taxes were $180 million compared to $158 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings, an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, and prior year tax return actualization.
For year-to-date 2011, income taxes were $407 million compared to $399 million for the corresponding period in 2010. The increase was primarily due to an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, partially offset by lower pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power’s future earnings potential. The level of Alabama Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include Alabama Power’s 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. Future earnings 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, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Changes in economic conditions impact sales for Alabama 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Alabama Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Alabama Power in Item 7 of the Form 10-K for additional information regarding the proposed coal combustion byproducts rule. Although its analysis is preliminary, Alabama Power estimates that the aggregate capital costs for compliance with these rules could range from $5 billion to $7 billion through 2020 if the rules are adopted as proposed. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Alabama Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit. The ultimate outcome of this matter cannot be determined at this time.
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Alabama Power in Item 7 and Note 3 of the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Alabama Power in Item 7 and Note 3 of the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, and includes many of the same defendants that were involved in the earlier case. Alabama Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality.
On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Alabama Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.
In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. On April 6, 2011, the EPA attempted to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. The EPA’s decision became effective May 6, 2011 and the court denied Alabama Power’s requested stay on May 12, 2011. Unless the court resolves Alabama Power’s appeal in its favor, the EPA’s rescission will continue to affect Alabama Power’s operations. The EPA’s rescission has affected unit availability

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and increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.
On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The State of Alabama is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program and to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the State of Alabama. The rule could have significant effects on Alabama Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Alabama Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Alabama Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Alabama Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
FERC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters” of Alabama Power in Item 7 of the Form 10-K for additional information. On June 8, 2011, Alabama Power filed an application with the FERC to relicense the Martin hydroelectric project located on the Tallapoosa River. The current license will expire in 2013. The ultimate outcome of this matter cannot be determined at this time.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama PSC Matters
Environmental Accounting Order
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – General” of Alabama Power in Item 7 of the Form 10-K for additional information regarding environmental regulations. Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.
Retail Rate Adjustments
See BUSINESS – “Rate Matters – Rate Structure and Cost Recovery Plans” of Alabama Power in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” and “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.
In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.
Natural Disaster Reserve
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information.
During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.
At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

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In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.
Retail Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of September 30, 2011 totaled $39 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at September 30, 2011 are included in deferred under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered fuel costs.
Income Tax Matters
Legislation
On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
In September 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, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (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 will have a positive impact on the future cash flows of Alabama Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Alabama Power estimates the potential increased cash flow for 2011 to be between approximately $150 million and $200 million. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities 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, and

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power’s financial statements.
On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of existing nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time.
See RISK FACTORS of Alabama Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Alabama Power’s financial condition remained stable at September 30, 2011. Alabama Power 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.
Net cash provided from operating activities totaled $1.56 billion for the first nine months of 2011, an increase of $403 million as compared to the first nine months of 2010. The increase in cash provided from operating activities was primarily due to accrued taxes and deferred income taxes related to benefits associated with bonus depreciation and other current liabilities. This increase was partially offset by decreases in accounts payable and net income. Net cash used for investing activities totaled $734 million for the first nine months of 2011 primarily due to gross property additions related to steam and nuclear generation equipment, nuclear fuel, transmission, and distribution expenditures. Net cash used for financing activities totaled $402 million for the first nine months of 2011 primarily due to issuances, redemptions, and a maturity of

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senior notes and payment of common stock dividends. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2011 include increases in cash and cash equivalents and accumulated deferred income taxes of $422 million and $401 million, respectively, related to additional bonus depreciation, $219 million in property, plant, and equipment associated with routine property additions and nuclear fuel, and $191 million in retained earnings, partially offset by decreases of $131 million in prepaid expenses related to income taxes and $125 million in other regulatory liabilities, deferred.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. There are no requirements through September 30, 2012 to fund maturities of long-term debt.
As of September 30, 2011, the approved construction program of Alabama Power included a base level investment of $0.9 billion for 2011, $0.9 billion for 2012, and $1.1 billion for 2013. Included in Alabama Power’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. Alabama Power anticipates that additional expenditures may be required to comply with anticipated statutes and regulations. Such additional expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013, respectively. If the EPA’s proposed Utility MACT rule is finalized as proposed, Alabama Power estimates that the potential incremental investments for new environmental regulations may exceed these estimates. The construction program is 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; Alabama 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.
Sources of Capital
Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power’s current liabilities sometimes exceed current assets because of Alabama Power’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Alabama Power had at September 30, 2011 cash and cash equivalents of approximately $576 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $60 million expire in 2011, $121 million expire in 2012, $35 million expire in 2013, $280 million expire in 2014, and $800 million expire in 2016. Of the credit arrangements expiring on or before September 30, 2012, $111 million contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama

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Power’s commercial paper borrowings and $794 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power 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 Alabama Power and other Southern Company subsidiaries. At September 30, 2011, Alabama Power had no commercial paper borrowings outstanding. During the third quarter 2011, Alabama Power had an average of $1 million of commercial paper outstanding at a weighted average interest rate of 0.10% per annum and the maximum amount outstanding was $25 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama Power 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 to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Alabama Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2011 were as follows:
                 
    Third Quarter   Year-to-Date
    2011   2011
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (24 )   $ (38 )
Contracts realized or settled
    9       29  
Current period changes(a)
    (14 )     (20 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (29 )   $ (29 )
 
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was a decrease of $5 million and an increase of $9 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Alabama Power had a net hedge volume of 31 million mmBtu with a weighted average contract cost approximately $1.04 per mmBtu above market prices, compared to 31 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.79 per mmBtu above market prices and compared to 34 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.14 per mmBtu above market prices.
Regulatory hedges relate to Alabama Power’s fuel-hedging program 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 clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.
Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:
                                 
            September 30, 2011        
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (29 )     (24 )     (5 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (29 )   $ (24 )   $ (5 )   $  
 
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 Alabama Power. 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.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In February 2011, Alabama Power’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured.
In March 2011, Alabama Power issued $250 million aggregate principal amount of Series 2011A 5.50% Senior Notes due March 15, 2041. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program. Alabama Power settled $200 million of interest rate hedges related to its Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In May 2011, Alabama Power issued $200 million aggregate principal amount of Series 2011B 3.950% Senior Notes due June 1, 2021 and $250 million aggregate principal amount of Series 2011C 5.200% Senior Notes due June 1, 2041. The net proceeds were used by Alabama Power for the redemption of $100 million aggregate principal amount of the Series GG 5 7/8% Senior Notes due February 1, 2046, $200 million aggregate principal amount of the Series II 5.875% Senior Notes due March 15, 2046, and $150 million aggregate principal amount of the Series JJ 6.375% Senior Notes due June 15, 2046.
In August 2011, 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 $300 million.
In September 2011, Alabama Power redeemed approximately $4 million of The Industrial Development Board of the Town of Wilsonville, Alabama Solid Waste Disposal Revenue Bonds (Alabama Power Company Plant Gaston), Series 2008.
Subsequent to September 30, 2011, Alabama Power announced the redemption that will occur on November 14, 2011 of approximately $100 million aggregate principal amount of its Series EE 5.75% Senior Notes due January 15, 2036.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GEORGIA POWER COMPANY

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)     (in millions)  
Operating Revenues:
                               
Retail revenues
  $ 2,609     $ 2,418     $ 6,494     $ 6,036  
Wholesale revenues, non-affiliates
    90       109       270       307  
Wholesale revenues, affiliates
    4       17       31       43  
Other revenues
    85       84       247       226  
 
                       
Total operating revenues
    2,788       2,628       7,042       6,612  
 
                       
Operating Expenses:
                               
Fuel
    838       928       2,299       2,443  
Purchased power, non-affiliates
    127       128       297       294  
Purchased power, affiliates
    193       143       513       437  
Other operations and maintenance
    453       435       1,294       1,224  
Depreciation and amortization
    180       182       531       426  
Taxes other than income taxes
    102       98       283       264  
 
                       
Total operating expenses
    1,893       1,914       5,217       5,088  
 
                       
Operating Income
    895       714       1,825       1,524  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    26       34       73       105  
Interest expense, net of amounts capitalized
    (90 )     (95 )     (257 )     (275 )
Other income (expense), net
    (4 )     (5 )     (10 )     (12 )
 
                       
Total other income and (expense)
    (68 )     (66 )     (194 )     (182 )
 
                       
Earnings Before Income Taxes
    827       648       1,631       1,342  
Income taxes
    303       224       583       433  
 
                       
Net Income
    524       424       1,048       909  
Dividends on Preferred and Preference Stock
    4       4       13       13  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 520     $ 420     $ 1,035     $ 896  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in millions)     (in millions)  
Net Income After Dividends on Preferred and Preference Stock
  $ 520     $ 420     $ 1,035     $ 896  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $5, respectively
    1       2       2       8  
 
                       
Comprehensive Income
  $ 521     $ 422     $ 1,037     $ 904  
 
                       
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Net income
  $ 1,048     $ 909  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    646       551  
Deferred income taxes
    422       225  
Deferred revenues
          (77 )
Deferred expenses
    (30 )     (54 )
Allowance for equity funds used during construction
    (73 )     (105 )
Pension, postretirement, and other employee benefits
    2       20  
Stock based compensation expense
    7       5  
Other, net
    (47 )     (10 )
Changes in certain current assets and liabilities —
               
-Receivables
    (68 )     (126 )
-Fossil fuel stock
    115       153  
-Prepaid income taxes
    81       2  
-Other current assets
    (2 )     4  
-Accounts payable
    (46 )     61  
-Accrued taxes
    (1 )     66  
-Accrued compensation
    (18 )     45  
-Other current liabilities
    43       38  
 
           
Net cash provided from operating activities
    2,079       1,707  
 
           
Investing Activities:
               
Property additions
    (1,363 )     (1,628 )
Nuclear decommissioning trust fund purchases
    (1,645 )     (570 )
Nuclear decommissioning trust fund sales
    1,641       546  
Cost of removal, net of salvage
    (21 )     (46 )
Change in construction payables, net of joint owner portion
    108       27  
Other investing activities
    (9 )     5  
 
           
Net cash used for investing activities
    (1,289 )     (1,666 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (575 )     (321 )
Proceeds —
               
Capital contributions from parent company
    199       681  
Pollution control revenue bonds issuances
    604        
Senior notes issuances
    550       1,950  
Other long-term debt issuances
    250        
Redemptions —
               
Pollution control revenue bonds
    (286 )      
Senior notes
    (277 )     (1,112 )
Other long-term debt
    (509 )     (3 )
Payment of preferred and preference stock dividends
    (13 )     (13 )
Payment of common stock dividends
    (672 )     (615 )
Other financing activities
    (3 )     (32 )
 
           
Net cash provided from (used for) financing activities
    (732 )     535  
 
           
Net Change in Cash and Cash Equivalents
    58       576  
Cash and Cash Equivalents at Beginning of Period
    8       14  
 
           
Cash and Cash Equivalents at End of Period
  $ 66     $ 590  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $27 and $39 capitalized for 2011 and 2010, respectively)
  $ 240     $ 231  
Income taxes (net of refunds)
    (2 )     107  
Noncash transactions — accrued property additions at end of period
    375       261  
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 66     $ 8  
Receivables —
               
Customer accounts receivable
    764       580  
Unbilled revenues
    235       172  
Under recovered regulatory clause revenues
    189       184  
Joint owner accounts receivable
    52       60  
Other accounts and notes receivable
    58       67  
Affiliated companies
    28       21  
Accumulated provision for uncollectible accounts
    (17 )     (11 )
Fossil fuel stock, at average cost
    509       624  
Materials and supplies, at average cost
    379       371  
Vacation pay
    77       78  
Prepaid income taxes
    1       99  
Other regulatory assets, current
    94       105  
Other current assets
    144       80  
 
           
Total current assets
    2,579       2,438  
 
           
Property, Plant, and Equipment:
               
In service
    26,918       26,397  
Less accumulated provision for depreciation
    10,198       9,966  
 
           
Plant in service, net of depreciation
    16,720       16,431  
Other utility plant, net
    57        
Nuclear fuel, at amortized cost
    427       386  
Construction work in progress
    3,774       3,287  
 
           
Total property, plant, and equipment
    20,978       20,104  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    63       70  
Nuclear decommissioning trusts, at fair value
    657       818  
Miscellaneous property and investments
    39       42  
 
           
Total other property and investments
    759       930  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    747       723  
Prepaid pension costs
    122       91  
Deferred under recovered regulatory clause revenues
    25       214  
Other regulatory assets, deferred
    1,282       1,207  
Other deferred charges and assets
    213       207  
 
           
Total deferred charges and other assets
    2,389       2,442  
 
           
Total Assets
  $ 26,705     $ 25,914  
 
           
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $ 254     $ 415  
Notes payable
    1       576  
Accounts payable —
               
Affiliated
    328       243  
Other
    580       574  
Customer deposits
    206       198  
Accrued taxes —
               
Accrued income taxes
    105       1  
Unrecognized tax benefits
    9       187  
Other accrued taxes
    252       328  
Accrued interest
    117       94  
Accrued vacation pay
    56       58  
Accrued compensation
    100       109  
Liabilities from risk management activities
    53       77  
Other cost of removal obligations, current
    31       31  
Nuclear decommissioning trust securities lending collateral
    37       144  
Other current liabilities
    162       134  
 
           
Total current liabilities
    2,291       3,169  
 
           
Long-term Debt
    8,422       7,931  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    4,256       3,718  
Deferred credits related to income taxes
    124       129  
Accumulated deferred investment tax credits
    222       229  
Employee benefit obligations
    716       684  
Asset retirement obligations
    729       705  
Other cost of removal obligations
    123       131  
Other deferred credits and liabilities
    237       211  
 
           
Total deferred credits and other liabilities
    6,407       5,807  
 
           
Total Liabilities
    17,120       16,907  
 
           
Preferred Stock
    45       45  
 
           
Preference Stock
    221       221  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - 9,261,500 shares
    398       398  
Paid-in capital
    5,504       5,291  
Retained earnings
    3,426       3,063  
Accumulated other comprehensive loss
    (9 )     (11 )
 
           
Total common stockholder’s equity
    9,319       8,741  
 
           
Total Liabilities and Stockholder’s Equity
  $ 26,705     $ 25,914  
 
           
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the 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. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. However, this has no impact on earnings as fuel cost recovery revenues generally equal fuel expenses.
Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$100   23.8   $139   15.5
 
Georgia Power’s net income after dividends on preferred and preference stock for the third quarter 2011 was $520 million compared to $420 million for the corresponding period in 2010. Georgia Power’s year-to-date 2011 net income after dividends on preferred and preference stock was $1.04 billion compared to $896 million for the corresponding period in 2010. The increases were primarily due to increases in retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011, partially offset by relatively cooler weather primarily in the month of September compared to the third quarter 2010, higher non-fuel operating expenses, and higher income taxes. The year-to-date increase was also due to a reduction in interest expense arising from the settlement of tax litigation with the Georgia Department of Revenue (DOR), partially offset by a decrease in the amortization of the regulatory liability related to other cost of removal obligations.
Retail Revenues
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$191   7.9   $458   7.6
 
In the third quarter 2011, retail revenues were $2.61 billion compared to $2.42 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $6.49 billion compared to $6.04 billion for the corresponding period in 2010.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues are as follows:
                                 
    Third Quarter     Year-to-Date  
    2011     2011  
    (in millions)   (% change)   (in millions)   (% change)
Retail — prior year
  $ 2,418             $ 6,036          
Estimated change in —
                               
Rates and pricing
    225       9.3       546       9.0  
Sales growth (decline)
    (11 )     (0.4 )     (7 )     (0.1 )
Weather
    (26 )     (1.1 )     (55 )     (0.9 )
Fuel cost recovery
    3       0.1       (26 )     (0.4 )
 
Retail – current year
  $ 2,609       7.9 %   $ 6,494       7.6 %
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to increases in retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011.
Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010. Weather-adjusted residential KWH sales decreased 1.3%, weather-adjusted commercial KWH sales increased 0.1%, and weather-adjusted industrial KWH sales were flat in the third quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted residential and commercial KWH sales each decreased 0.3% and weather-adjusted industrial KWH sales increased 1.8% year-to-date 2011 when compared to the corresponding period in 2010. Increased demand in the primary metals sector was the main contributor to the increase in weather-adjusted industrial KWH sales for year-to-date 2011.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $3 million in the third quarter 2011 when compared to the corresponding period in 2010 due to higher KWHs purchased, partially offset by lower KWHs generated. Retail fuel cost recovery revenues decreased $26 million for year-to-date 2011 when compared to the corresponding period in 2010 due to the lower cost of purchased power per KWH purchased and lower KWHs generated. See Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters – Fuel Cost Recovery” herein for additional information.
Electric rates 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 costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(19)   (17.4)   $(37)   (12.1)
 
Wholesale revenues from non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2011, wholesale revenues from non-affiliates were $90 million compared to $109 million for the corresponding period in 2010, reflecting a $24 million decrease in energy revenues, partially offset by a $5 million increase in capacity revenues. The decrease in the third quarter 2011 was primarily due to a 31.7% decrease in KWH sales from lower demand as a result of less favorable weather in the third quarter 2011 and current economic conditions.
For year-to-date 2011, wholesale revenues from non-affiliates were $270 million compared to $307 million for the corresponding period in 2010. The decrease was primarily due to a $38 million decrease in energy revenues, slightly offset by an increase in capacity revenues. The decrease in year-to-date 2011 was primarily due to a 19.8% decrease in KWH sales from lower demand resulting from more favorable weather in the first quarter 2010, lower market costs of available energy compared to Georgia Power-owned generation, and the expiration of a long-term unit power sales contract in May 2010.
Wholesale Revenues — Affiliates
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(13)   (76.5)   $(12)   (27.9)
 
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the third quarter 2011, wholesale revenues from affiliates were $4 million compared to $17 million for the corresponding period in 2010. For year-to-date 2011, wholesale revenues from affiliates were $31 million compared to $43 million for the corresponding period in 2010. These decreases were due to an 80.8% decrease and a 26.2% decrease in KWH sales due to lower demand in the third quarter and year-to-date 2011, respectively, primarily because the market cost of available energy was lower than the cost of Georgia Power-owned generation.
Other Revenues
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$1   1.2   $21   9.3
 
In the third quarter 2011, other revenues were $85 million compared to $84 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material. For year-to-date 2011, other revenues were $247 million compared to $226 million for the corresponding period in 2010. The increase was primarily due to a $21 million increase in transmission revenues as a result of new contracts that replaced the transmission component of a unit power sales contract that expired in May 2010 and increased usage of Georgia Power’s transmission system by non-affiliate companies.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2011   Year-to-Date 2011
    vs.   vs.
    Third Quarter 2010   Year-to-Date 2010
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ (90 )     (9.7 )   $ (144 )     (5.9 )
Purchased power — non-affiliates
    (1 )     (0.8 )     3       1.0  
Purchased power — affiliates
    50       35.0       76       17.4  
                     
Total fuel and purchased power expenses
  $ (41 )           $ (65 )        
                     
 
*   Fuel includes fuel purchased by Georgia Power 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 the third quarter 2011, total fuel and purchased power expenses were $1.16 billion compared to $1.20 billion for the corresponding period in 2010. The decrease was primarily due to a 5.6% decrease in total KWHs generated and purchased to meet demand, partially offset by a 0.4% increase in the average cost of fuel and purchased power.
For year-to-date 2011, total fuel and purchased power expenses were $3.11 billion compared to $3.17 billion for the corresponding period in 2010. The decrease was primarily due to a 3.6% decrease in total KWHs generated and purchased primarily due to lower customer demand as a result of significantly colder weather in the first quarter 2010 and a 0.7% decrease in the average cost of fuel and purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since fuel expenses are generally offset by fuel revenues through Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL — “Georgia PSC Matters — Fuel Cost Recovery” herein for additional information.
Details of Georgia Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter     Third Quarter     Percent     Year-to-Date     Year-to-Date     Percent  
Average Cost   2011     2010     Change     2011     2010     Change  
    (cents per net KWH)             (cents per net KWH)          
Fuel
    3.99       3.97       0.5       3.90       3.84       1.6  
Purchased power
    5.51       5.50       0.2       5.61       5.90       (4.9 )
 
In the third quarter 2011, fuel expense was $838 million compared to $928 million for the corresponding period in 2010. This decrease was due to a 12.2% decrease in KWHs generated, partially offset by a 0.5% increase in the average cost of fuel per KWH generated. The decrease in KWHs generated and the increase in cost are primarily due to lower customer demand and increased global demand for coal as well as an increase in the price of nuclear fuel.
For year-to-date 2011, fuel expense was $2.30 billion compared to $2.44 billion for the corresponding period in 2010. The decrease was primarily due to a 9.8% decrease in KWHs generated, partially offset by a 1.6% increase in the average cost of fuel per KWH generated. The decrease in KWHs generated and the increase in cost are primarily the result of higher prices as described above.
Affiliates
In the third quarter 2011, purchased power expense from affiliates was $193 million compared to $143 million for the corresponding period in 2010. The increase was due to a 17.1% increase in the volume of KWHs purchased, as system resources dispatched at lower cost than Georgia Power units and a 7.4% increase in the average cost per KWH purchased, reflecting a higher level of purchases during peaking hours in 2011.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2011, purchased power expense from affiliates was $513 million compared to $437 million in the corresponding period in 2010. The increase was due to a 23.8% increase in the volume of KWHs purchased, primarily as the result of a new PPA that began in June 2010, partially offset by a 5.5% decrease in the average cost per KWH purchased, reflecting lower gas prices.
Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$18   4.1   $70   5.7
 
In the third quarter 2011, other operations and maintenance expenses were $453 million compared to $435 million for the corresponding period in 2010. The increase was primarily due to a $5 million increase in distribution maintenance expense, a $6 million increase in customer assistance expense related to new demand side management programs in 2011, and a $2 million increase in uncollectible account expense as a result of higher revenues and the current economic conditions.
For year-to-date 2011, other operations and maintenance expenses were $1.29 billion compared to $1.22 billion for the corresponding period in 2010. The increase was primarily due to a $23 million increase in scheduled outages and maintenance for generating units, a $10 million increase in overhead line maintenance, an $8 million increase in customer assistance expense related to new demand side management programs in 2011, and a $6 million increase in uncollectible account expense as a result of higher revenues and the current economic conditions.
Depreciation and Amortization
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2)   (1.1)   $105   24.6
 
In the third quarter 2011, depreciation and amortization was $180 million compared to $182 million for the corresponding period in 2010. The decrease when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, depreciation and amortization was $531 million compared to $426 million for the corresponding period in 2010. The increase was primarily due to a $94 million decrease in the amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC. See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters — Rate Plans” in Item 8 of the Form 10-K for additional information on the other cost of removal regulatory liability.
Taxes Other Than Income Taxes
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$4   4.1   $19   7.2
 
In the third quarter 2011, taxes other than income taxes were $102 million compared to $98 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.
For year-to-date 2011, taxes other than income taxes were $283 million compared to $264 million for the corresponding period in 2010. The increase was due to a $10 million increase in property taxes and an $8 million increase in franchise fees related to higher operating revenues.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(8)   (23.5)   $(32)   (30.5)
 
In the third quarter 2011, AFUDC equity was $26 million compared to $34 million for the corresponding period in 2010. For year-to-date 2011, AFUDC equity was $73 million compared to $105 million for the corresponding period in 2010. The decreases were primarily due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC capitalized. See Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements herein under “State PSC Matters – Georgia Power – Nuclear Construction,” and FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for additional information.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(5)   (5.3)   $(18)   (6.5)
 
In the third quarter 2011, interest expense, net of amounts capitalized was $90 million compared to $95 million for the corresponding period in 2010. The decrease in third quarter 2011 compared to the corresponding period in 2010 was primarily due to lower interest expense on variable rate pollution control bonds. For year-to-date 2011, interest expense, net of amounts capitalized was $257 million compared to $275 million for the corresponding period in 2010. The decrease was primarily due to a reduction of $23 million in interest expense related to the settlement of tax litigation with the Georgia DOR, partially offset by a reduction in interest capitalized due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, as described above. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters” herein, Notes 3 and 5 to the financial statements of Georgia Power under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, in Item 8 of the Form 10-K, and Note (G) herein for additional information.
Income Taxes
             
Third Quarter 2011 vs. Third Quarter 2010   Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$79   35.3   $150   34.6
 
In the third quarter 2011, income taxes were $303 million compared to $224 million for the corresponding period in 2010. The increase in income taxes was primarily due to higher pre-tax earnings and a decrease in non-taxable AFUDC equity, as described previously.
For year-to-date 2011, income taxes were $583 million compared to $433 million for the corresponding period in 2010. The increase in income taxes was primarily due to higher pre-tax earnings, the recognition in the first quarter 2010 of certain state income tax credits, and a decrease in non-taxable AFUDC equity.

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FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s 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. Future earnings 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, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Changes in economic conditions impact sales for Georgia 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Georgia Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the proposed coal combustion byproducts rule. Although its analysis is preliminary, Georgia Power estimates that the aggregate capital costs for compliance with these rules could range from $5 billion to $7 billion through 2020 if the rules are adopted as proposed. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Georgia Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Georgia Power in Item 7 and Note 3 of the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

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Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Georgia Power in Item 7 and Note 3 of the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Georgia Power, and includes many of the same defendants that were involved in the earlier case. Georgia Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality.
On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Georgia Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.
In April 2010, the EPA proposed an Industrial Boiler 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 published the final rule on March 21, 2011 and, at the same time, issued a notice of intent to reconsider the final rule to allow for additional public review and comment. The EPA has announced plans to finalize the rule by April 30, 2012. The effect of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time. On October 18, 2011, the Georgia PSC approved Georgia Power’s request to further delay the decision to convert Plant Mitchell Unit 3 from coal to biomass for two to four years, until there is greater clarity regarding the Industrial Boiler MACT rule and other proposed and recently adopted regulations. Georgia Power will file semi-annual construction monitoring reports on March 1 and August 15 throughout the delay period.

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On June 23, 2011, the EPA published its determination that the 20-county area within metropolitan Atlanta has air quality which attains the 1997 eight-hour ozone air quality standard. In March 2008, the EPA adopted a more stringent eight-hour ozone air quality standard, which it began to implement in September 2011. The 2008 standard is expected to result in designation of new nonattainment areas within Georgia Power’s service territory and could result in additional required reductions in nitrogen oxide emissions. The ultimate outcome of this matter cannot be determined at this time.
On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The State of Georgia is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program and to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the State of Georgia. Georgia Power may need to purchase allowances to demonstrate compliance with the CSAPR. The rule could have significant effects on Georgia Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Georgia Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.
On March 22, 2011, the Board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule, which is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. On June 29, 2011, the modifications were approved and the compliance dates for certain of Georgia Power’s coal-fired generating units were changed as follows:
     
Branch 1
  December 31, 2013
Branch 2
  October 1, 2013
Branch 3
  October 1, 2015
Branch 4
  December 31, 2015
See “Georgia PSC Matters – 2011 Integrated Resource Plan Update” herein for additional information.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at

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many of Georgia Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Georgia Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.
Georgia PSC Matters
Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information. As of September 30, 2011, Georgia Power had a total under recovered fuel cost balance of approximately $214 million compared to $398 million at December 31, 2010.
On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.
2011 Integrated Resource Plan Update
See “Environmental Matters – Air Quality” and “– Water Quality” herein and BUSINESS – “Rate Matters – Integrated Resource Planning” of Georgia Power in Item 1, MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality,” “– Water Quality,” and “– Coal Combustion Byproducts” of Georgia Power in Item 7, and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; and the 2010 ARP.
On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.

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Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s 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. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Georgia Power’s financial statements.
The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.
Storm Damage Recovery
During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2011, the balance in the regulatory asset related to storm damage was $45 million. As a result of this regulatory treatment, the costs related to the storms are not expected to have a material impact on Georgia Power’s financial statements. See Note 1 to the financial statements of Georgia Power under “Storm Damage Reserve” in Item 8 of the Form 10-K for additional information.
Income Tax Matters
Legislation
On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. 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 June 10, 2011, Georgia Power and the Georgia DOR agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Georgia Power in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, for additional information.

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Bonus Depreciation
In September 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, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (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 will have a positive impact on the future cash flows of Georgia Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Georgia Power estimates the potential increased cash flow for 2011 to be between approximately $275 million and $350 million. The ultimate outcome of this matter cannot be determined at this time.
Construction
Nuclear
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 of the Form 10-K for information regarding the construction of Plant Vogtle Units 3 and 4, which are expected to attain commercial operation in 2016 and 2017, respectively.
In December 2010, Westinghouse submitted a revision to the supporting documents for the AP1000 Design Certification Amendment (DCA) to the NRC. On January 24, 2011, the Advisory Committee on Reactor Safeguards endorsed the issuance of the Construction and Operating Licenses (COLs) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. On September 27 and 28, 2011, the NRC held the mandatory hearing for the COLs and Georgia Power’s request for a second limited work authorization. On October 18, 2011, the Atomic Safety and Licensing Board (ASLB) denied the remaining motions seeking to re-open the Plant Vogtle Units 3 and 4 licensing proceeding; however, on October 27, 2011, the petitioners requested reconsideration of this decision and, on November 2, 2011, further appealed to the NRC to admit their contentions, should they again be denied by the ASLB. The remaining steps in the regulatory process are to address the status of these petitions and to obtain the NRC approvals of the DCA and the COLs, which Georgia Power expects in late 2011. Issuance of the COLs by the NRC staff generally would be expected to occur within 10 days after the NRC’s decision. However, due to certain administrative procedural requirements, it is possible that the effective date of the DCA and issuance of the COLs could occur in early 2012. In this case, the NRC could approve Georgia Power’s request for a second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in late 2011.
In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the Georgia PSC Public Interest Advocacy Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. In May 2011, the Georgia PSC initiated a separate proceeding to address the issue. On August 2, 2011, the Georgia PSC voted to approve a settlement agreement between Georgia Power and the Georgia PSC Public Interest Advocacy Staff whereby the proposed risk sharing mechanisms were withdrawn. On August 16, 2011, the Georgia PSC voted to approve Georgia Power’s fourth semi-annual construction monitoring report including total costs of $1.3 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2010. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected

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financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs capitalized in 2009 and 2010 over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2011, approximately $78 million of these 2009 and 2010 costs were included in construction work in progress.
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims. During the course of construction activities, issues have materialized that may impact the project budget and schedule, including potential costs associated with compressing the project schedule to meet the projected commercial operation dates. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.
On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. While Georgia Power will continue to monitor this situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of its existing nuclear generating units.
The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. The task force report supported completion of the certification of the AP1000 reactor design being used at Plant Vogtle Units 3 and 4, noting that the design has many of the features necessary to address the task force’s recommendations.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. Similar additional challenges at the state and federal level are expected as construction proceeds.
The ultimate outcome of these matters cannot be determined at this time.
Other Construction
Georgia Power is currently constructing Plant McDonough Units 4, 5, and 6 which are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through December 31, 2010. Georgia Power filed its second quarter 2011 construction monitoring report on August 26, 2011, including actual project expenditures incurred through June 30, 2011 as well as a request to approve a 4.6% increase in the current certified

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amount. The Georgia PSC is scheduled to issue its decision on February 16, 2012. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power’s business activities 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, 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 Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Georgia Power’s financial condition remained stable at September 30, 2011. Georgia Power 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.
Net cash provided from operating activities totaled $2.08 billion for the first nine months of 2011, compared to $1.71 billion for the corresponding period in 2010. The $372 million increase in cash provided from operating activities is primarily due to higher retail operating revenues and increased deferred income taxes in 2011. Net cash used for investing activities totaled $1.29 billion primarily due to gross property additions to utility plant in the first nine months of 2011. Net cash used for financing activities totaled $732 million for the first nine months of 2011, compared to $535 million net cash provided from financing activities for the corresponding period in 2010. The $1.27 billion decrease is primarily due to higher capital contributions from Southern Company and an increased amount of debt issued in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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Significant balance sheet changes for the first nine months of 2011 include an increase of $874 million in total property, plant, and equipment, an increase of $538 million in accumulated deferred income taxes related to bonus depreciation and repairs accounting, an increase of $491 million in long-term debt primarily to replace short-term debt, and an increase in paid in capital of $213 million reflecting equity contributions from Southern Company. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters – Bonus Depreciation” herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $254 million will be required through September 30, 2012 to fund maturities of long-term debt.
The construction program of Georgia Power is estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. In addition, Georgia Power estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million for 2011, $191 million to $651 million for 2012, and $476 million to $1.4 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Georgia Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. The construction program is 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; Georgia 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.
In June 2011, Georgia Power entered into four PPAs totaling 1,562 MWs annually, which are subject to certification by the Georgia PSC. See FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – 2011 Integrated Resource Plan Update” herein for additional information. If approved, these PPAs are expected to result in additional obligations of approximately $84 million in 2015, $102 million in 2016, and $1.41 billion thereafter. However, the PPAs include an early termination provision through March 27, 2012 that allows Georgia Power to terminate one or more of the PPAs if Georgia Power does not retire certain coal-fired units as a result of the potential rules and regulations being developed by the EPA. Of the total capacity, 564 MWs will expire in 2027 and 998 MWs in 2030. Three of the PPAs are with Southern Power and are also subject to FERC approval.
Also in June 2011, Georgia Power renewed two rail car leases that contain obligations upon expiration with respect to the residual value of the leased property. These operating leases expire in 2014 and 2018 and Georgia Power’s maximum obligation is approximately $11 million and $20 million, respectively. At the termination of the leases, at Georgia Power’s option, Georgia Power may either exercise its purchase option or the property can be sold to a third party. Estimated annual commitments for the three-year lease and seven-year lease are approximately $1 million and $2 million, respectively.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, Georgia Power plans 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, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Georgia Power in Item 7 of the Form 10-K for additional information.
In June 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 borrowings by Georgia Power related to the construction of 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 Power’s 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 $3.46 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 COLs for Plant Vogtle Units 3 and 4 from the 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. See FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for more information on Plant Vogtle Units 3 and 4.
Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at September 30, 2011 approximately $66 million of cash and cash equivalents and approximately $1.74 billion of unused committed credit arrangements with banks. As of September 30, 2011, of the unused credit arrangements, $250 million expire in 2014 and $1.50 billion expire in 2016. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. At September 30, 2011, the credit arrangements were dedicated to providing liquidity support to Georgia Power’s commercial paper program and approximately $868 million of purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Georgia Power 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 Georgia Power and other Southern Company subsidiaries. At September 30, 2011, Georgia Power had no commercial paper borrowings outstanding. During the third quarter 2011, Georgia Power had an average of $110 million of commercial paper outstanding with a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $364 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Georgia Power 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 to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $68 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.5 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Georgia Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Georgia Power continues to manage a natural gas hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the third quarter 2011 relative to fuel and electricity prices when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2011 were as follows:
                 
    Third Quarter   Year-to-Date
    2011   2011
    Changes   Changes
    Fair Value  
    (in millions)  
Contracts outstanding at the beginning of the period, assets (liabilities), net
    $(67 )     $(100 )
Contracts realized or settled
    26       72  
Current period changes(a)
    (25 )     (38 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
    $(66 )     $(66 )
 
 
(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 three and nine months ended September 30, 2011 was an increase of $1 million and an increase of $34 million, respectively, all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Georgia Power had a net hedge volume of 66 million mmBtu with a weighted average contract cost approximately $1.24 per mmBtu above market prices, compared to 65 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $1.18 per mmBtu above market prices and compared to 59 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.74 per mmBtu above market prices.
Regulatory hedges relate to Georgia Power’s natural gas hedging program 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 mechanism.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:
                                 
            September 30, 2011          
            Fair Value Measurements          
    Total   Maturity  
    Fair Value   Year 1   Years 2&3   Years 4&5
            (in millions)          
Level 1
  $     $     $     $  
Level 2
    (66 )     (53 )     (13 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (66 )   $ (53 )   $ (13 )   $  
 
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 Georgia Power. 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.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Georgia Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In December 2010, the Development Authority of Floyd County issued $53 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010 for the benefit of Georgia Power. These bonds were purchased and held by Georgia Power. In January 2011, Georgia Power remarketed these bonds to investors.
In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.
In January 2011, 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 short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.
In March 2011, Georgia Power’s $300 million variable rate bank term loan due on March 4, 2011 matured and was partially replaced by two one-year $125 million aggregate principal amount variable rate bank loans that bear interest based on one-month LIBOR.
In April 2011, Georgia Power issued $250 million aggregate principal amount of Series 2011B 3.0% Senior Notes due April 15, 2016. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.
In April 2011, Georgia Power purchased and held $113.5 million of pollution control revenue bonds. In June 2011, the bonds were remarketed to investors.
In July 2011, Georgia Power redeemed $67 million of the Development Authority of Appling County Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), First Series 2006.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In July 2011, approximately $8 million of Georgia Power’s Development Authority of Cobb County Pollution Control Revenue Bonds (Georgia Power Company Plant McDonough Project), First Series 1991 matured.
In September 2011, Georgia Power redeemed (i) $140.7 million aggregate principal amount of Series M 5.40% Senior Insured Notes due March 1, 2033, (ii) $35 million aggregate principal amount of Savannah Electric Series F 5.50% Senior Notes due December 12, 2028, (iii) approximately $14.1 million aggregate principal amount of Development Authority of Coweta County Pollution Control Revenue Bonds (Georgia Power Company Plant Yates Project), Second Series 2001, and (iv) $200 million aggregate principal amount of Series G 5-7/8% Junior Subordinated Notes due January 15, 2044 and the related Trust Preferred Securities of Georgia Power Capital Trust VII (as well as approximately $6.2 million of such Series G Junior Subordinated Notes related to Georgia Power’s ownership of the common securities of Georgia Power Capital Trust VII).
In September 2011, Georgia Power remarketed $173 million aggregate principal amount of the Development Authority of Bartow County Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $114.3 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2009 to investors.
In September 2011, the Development Authority of Appling County issued $67 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), First Series 2011 for the benefit of Georgia Power.
Subsequent to September 30, 2011, Georgia Power announced the redemption that will occur on November 21, 2011 of $53 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1999.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

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GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 362,109     $ 396,671     $ 957,409     $ 1,021,530  
Wholesale revenues, non-affiliates
    33,921       31,211       103,814       86,041  
Wholesale revenues, affiliates
    52,833       37,995       79,825       88,386  
Other revenues
    19,167       17,578       50,855       47,381  
 
                       
Total operating revenues
    468,030       483,455       1,191,903       1,243,338  
 
                       
Operating Expenses:
                               
Fuel
    220,305       237,003       530,773       585,167  
Purchased power, non-affiliates
    20,046       12,771       37,938       34,615  
Purchased power, affiliates
    9,941       20,282       39,108       51,725  
Other operations and maintenance
    74,144       67,178       227,236       202,202  
Depreciation and amortization
    32,673       34,032       96,733       90,651  
Taxes other than income taxes
    29,467       29,293       79,230       78,586  
 
                       
Total operating expenses
    386,576       400,559       1,011,018       1,042,946  
 
                       
Operating Income
    81,454       82,896       180,885       200,392  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    2,434       1,424       7,091       4,504  
Interest income
    22       31       56       87  
Interest expense, net of amounts capitalized
    (15,156 )     (13,764 )     (43,208 )     (38,286 )
Other income (expense), net
    (451 )     (471 )     (1,461 )     (1,355 )
 
                       
Total other income and (expense)
    (13,151 )     (12,780 )     (37,522 )     (35,050 )
 
                       
Earnings Before Income Taxes
    68,303       70,116       143,363       165,342  
Income taxes
    25,535       25,658       52,451       60,166  
 
                       
Net Income
    42,768       44,458       90,912       105,176  
Dividends on Preference Stock
    1,551       1,551       4,652       4,652  
 
                       
Net Income After Dividends on Preference Stock
  $ 41,217     $ 42,907     $ 86,260     $ 100,524  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preference Stock
  $ 41,217     $ 42,907     $ 86,260     $ 100,524  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $-, $-, $-, and $(542), respectively
                      (863 )
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $270, and $286, respectively
    143       143       430       455  
 
                       
Total other comprehensive income (loss)
    143       143       430       (408 )
 
                       
Comprehensive Income
  $ 41,360     $ 43,050     $ 86,690     $ 100,116  
 
                       
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2011     2010  
    (in thousands)  
Operating Activities:
               
Net income
  $ 90,912     $ 105,176  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    101,335       95,491  
Deferred income taxes
    56,869       55,355  
Allowance for equity funds used during construction
    (7,091 )     (4,504 )
Pension, postretirement, and other employee benefits
    (179 )     2,883  
Stock based compensation expense
    1,055       959  
Other, net
    (5,787 )     2,570  
Changes in certain current assets and liabilities —
               
-Receivables
    (13,605 )     (67,814 )
-Prepayments
    7,745       2,667  
-Fossil fuel stock
    36,802       29,483  
-Materials and supplies
    (6,382 )     (1,363 )
-Prepaid income taxes
    36,081       (9,558 )
-Property damage cost recovery
          34  
-Other current assets
    (571 )      
-Accounts payable
    (65 )     12,003  
-Accrued taxes
    22,186       18,166  
-Accrued compensation
    (4,290 )     2,695  
-Other current liabilities
    10,284       10,776  
 
           
Net cash provided from operating activities
    325,299       255,019  
 
           
Investing Activities:
               
Property additions
    (228,696 )     (203,911 )
Distribution of restricted cash from pollution control revenue bonds
          6,347  
Cost of removal, net of salvage
    (9,137 )     (750 )
Change in construction payables
    636       (17,792 )
Payments pursuant to long-term service agreements
    (6,173 )     (4,211 )
Other investing activities
    303       (295 )
 
           
Net cash used for investing activities
    (243,067 )     (220,612 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (56,607 )     (88,733 )
Proceeds —
               
Common stock issued to parent
    50,000       50,000  
Capital contributions from parent company
    1,569       3,571  
Pollution control revenue bonds
          21,000  
Senior notes
    125,000       300,000  
Redemptions —
               
Senior notes
    (553 )     (140,413 )
Other long-term debt
    (110,000 )      
Payment of preference stock dividends
    (4,652 )     (4,652 )
Payment of common stock dividends
    (82,500 )     (78,225 )
Other financing activities
    (3,593 )     (3,280 )
 
           
Net cash provided from (used for) financing activities
    (81,336 )     59,268  
 
           
Net Change in Cash and Cash Equivalents
    896       93,675  
Cash and Cash Equivalents at Beginning of Period
    16,434       8,677  
 
           
Cash and Cash Equivalents at End of Period
  $ 17,330     $ 102,352  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $2,826 and $1,795 capitalized for 2011 and 2010, respectively)
  $ 36,427     $ 28,394  
Income taxes (net of refunds)
    (46,319 )     13,862  
Noncash transactions — accrued property additions at end of period
    15,820       28,670  
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Assets   2011     2010  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 17,330     $ 16,434  
Receivables —
               
Customer accounts receivable
    91,252       74,377  
Unbilled revenues
    58,813       64,697  
Under recovered regulatory clause revenues
    9,840       19,690  
Other accounts and notes receivable
    14,829       9,867  
Affiliated companies
    15,429       7,859  
Accumulated provision for uncollectible accounts
    (1,863 )     (2,014 )
Fossil fuel stock, at average cost
    128,283       167,155  
Materials and supplies, at average cost
    51,111       44,729  
Other regulatory assets, current
    22,491       20,278  
Prepaid expenses
    22,342       58,412  
Other current assets
    1,838       3,585  
 
           
Total current assets
    431,695       485,069  
 
           
Property, Plant, and Equipment:
               
In service
    3,813,901       3,634,255  
Less accumulated provision for depreciation
    1,108,710       1,069,006  
 
           
Plant in service, net of depreciation
    2,705,191       2,565,249  
Construction work in progress
    231,156       209,808  
 
           
Total property, plant, and equipment
    2,936,347       2,775,057  
 
           
Other Property and Investments
    16,343       16,352  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    52,219       46,357  
Prepaid pension costs
    9,414       7,291  
Other regulatory assets, deferred
    259,136       219,877  
Other deferred charges and assets
    35,318       34,936  
 
           
Total deferred charges and other assets
    356,087       308,461  
 
           
Total Assets
  $ 3,740,472     $ 3,584,939  
 
           
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $     $ 110,000  
Notes payable
    36,577       93,183  
Accounts payable —
               
Affiliated
    62,464       46,342  
Other
    53,842       68,840  
Customer deposits
    35,859       35,600  
Accrued taxes —
               
Accrued income taxes
    8,587       3,835  
Other accrued taxes
    25,014       7,944  
Accrued interest
    18,175       13,393  
Accrued compensation
    10,169       14,459  
Other regulatory liabilities, current
    33,080       27,060  
Liabilities from risk management activities
    10,205       9,415  
Other current liabilities
    21,015       19,766  
 
           
Total current liabilities
    314,987       449,837  
 
           
Long-term Debt
    1,235,344       1,114,398  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    454,530       382,876  
Accumulated deferred investment tax credits
    7,097       8,109  
Employee benefit obligations
    76,695       76,654  
Other cost of removal obligations
    213,113       204,408  
Other regulatory liabilities, deferred
    43,399       42,915  
Other deferred credits and liabilities
    164,752       132,708  
 
           
Total deferred credits and other liabilities
    959,586       847,670  
 
           
Total Liabilities
    2,509,917       2,411,905  
 
           
Preference Stock
    97,998       97,998  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - September 30, 2011: 4,142,717 shares
               
- December 31, 2010: 3,642,717 shares
    353,060       303,060  
Paid-in capital
    541,706       538,375  
Retained earnings
    240,088       236,328  
Accumulated other comprehensive loss
    (2,297 )     (2,727 )
 
           
Total common stockholder’s equity
    1,132,557       1,075,036  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,740,472     $ 3,584,939  
 
           
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the 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. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Gulf Power in Item 7 of the Form 10-K.
On July 8, 2011, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates and charges to the extent necessary to generate additional gross annual revenues in the amount of $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012.
On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, to be operative beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.
RESULTS OF OPERATIONS
Net Income
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.7)   (3.9)   $(14.2)   (14.2)
 
Gulf Power’s net income after dividends on preference stock for the third quarter 2011 was $41.2 million compared to $42.9 million for the corresponding period in 2010. The decrease was primarily due to an increase in other operations and maintenance expenses for the third quarter 2011, partially offset by higher wholesale capacity revenues from non-affiliates.
Gulf Power’s net income after dividends on preference stock for year-to-date 2011 was $86.3 million compared to $100.5 million for the corresponding period in 2010. The decrease was primarily due to an increase in other operations and maintenance expenses for year-to-date 2011, relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010, and significantly colder weather in the first quarter 2010. These decreases were partially offset by an increase in AFUDC equity, which is non-taxable.

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

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(34.6)   (8.7)   $(64.1)   (6.3)
 
In the third quarter 2011, retail revenues were $362.1 million compared to $396.7 million for the corresponding period in 2010. For year-to-date 2011, retail revenues were $957.4 million compared to $1.02 billion for the corresponding period in 2010.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
  2011   2011
    (in millions)   (% change)   (in millions)   (% change)
 
Retail - prior year
  $ 396.7             $ 1,021.5          
Estimated change in -
                               
Rates and pricing
    (0.1 )     (0.0 )     (4.0 )     (0.4 )
Sales growth (decline)
    2.4       0.6       5.7       0.6  
Weather
    (3.1 )     (0.8 )     (11.0 )     (1.1 )
Fuel and other cost recovery
    (33.8 )     (8.5 )     (54.8 )     (5.4 )
 
Retail - current year
  $ 362.1       (8.7 )%   $ 957.4       (6.3 )%
 
Revenues associated with changes in rates and pricing was relatively flat in the third quarter 2011 due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower coal generation in the third quarter 2011, partially offset by an increase related to interim retail rate revenues. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Base Rate Case” herein for additional information.
Revenues associated with changes in rates and pricing decreased year-to-date 2011 when compared to the corresponding period in 2010 primarily due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower coal generation, partially offset by an increase related to interim retail rate revenues.
Annually, Gulf Power petitions the Florida PSC for recovery of projected environmental compliance costs including any true-up amount from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.3% and 2.2%, respectively, due to lower use per customer. KWH energy sales to industrial customers increased 9.8% primarily due to the addition of a new large customer and a billing adjustment recorded in July 2011.
Revenues attributable to changes in sales increased for year-to-date 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential customers increased 1.1% due to an increase in customers and higher use per customer. The change in weather-adjusted KWH energy sales to commercial customers was relatively flat. KWH energy sales to industrial customers increased 8.8% primarily due to the addition of a new large customer and changes in customer production levels.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues attributable to changes in weather decreased in the third quarter 2011 when compared to the corresponding period for 2010 due to relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010.
Revenues attributable to changes in weather decreased year-to-date 2011 when compared to the corresponding period for 2010 due to relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010, and significantly colder weather in the first quarter 2010.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 primarily due to lower recoverable fuel and purchased power expenses. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$2.7   8.7   $17.8   20.7
 
Wholesale revenues from non-affiliates are predominantly unit power sales under long-term contracts to other Florida and Georgia utilities. Revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. Wholesale revenues from non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.
In the third quarter 2011, wholesale revenues from non-affiliates were $33.9 million compared to $31.2 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 7.2% increase in KWH energy sales and a 12.9% increase in price related to higher capacity rates in the third quarter 2011.
For year-to-date 2011, wholesale revenues from non-affiliates were $103.8 million compared to $86.0 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 9.2% increase in KWH energy sales and a 30.2% increase in price related to higher capacity rates as a result of contracts effective in June 2010.
Wholesale Revenues – Affiliates
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$14.8   39.1   $(8.6)   (9.7)
 
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2011, wholesale revenues from affiliates were $52.8 million compared to $38.0 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 63.9% increase in KWH energy sales as a result of increased utilization of Gulf Power generation to serve Southern Company system territorial demand. The increase was partially offset by a 15.1% decrease in price related to lower Gulf Power energy rates in the third quarter 2011.
For year-to-date 2011, wholesale revenues from affiliates were $79.8 million compared to $88.4 million for the corresponding period in 2010. The decrease was primarily due to decreased energy revenues related to a 6.7% decrease in KWH sales as a result of less Gulf Power generation being utilized to serve Southern Company system territorial demand and a 2.9% decrease in price related to lower Gulf Power energy rates for year-to-date 2011.
Other Revenues
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.6   9.0   $3.5   7.3
 
In the third quarter 2011, other revenues were $19.2 million compared to $17.6 million for the corresponding period in 2010. For year-to-date 2011, other revenues were $50.9 million compared to $47.4 million for the corresponding period in 2010. The increases were primarily due to increases in revenues from other energy services.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2011   Year-to-Date 2011
    vs.   vs.
    Third Quarter 2010   Year-to-Date 2010
    (change in millions)   (% change)   (change in millions)   (% change)
 
Fuel*
  $ (16.7 )     (7.0 )   $ (54.4 )     (9.3 )
Purchased power – non-affiliates
    7.3       57.0       3.3       9.6  
Purchased power – affiliates
    (10.3 )     (51.0 )     (12.6 )     (24.4 )
                     
Total fuel and purchased power expenses
  $ (19.7 )           $ (63.7 )        
                     
     
*   Fuel includes fuel purchased by Gulf Power 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 the third quarter 2011, total fuel and purchased power expenses were $250.3 million compared to $270.0 million for the corresponding period in 2010. The net decrease in fuel and purchased power expenses was due to a $55.7 million decrease in the average cost of purchased power and a $10.6 million decrease in the average cost of fuel, partially offset by a $46.6 million net increase related to total KWHs generated and purchased.
For year-to-date 2011, total fuel and purchased power expenses were $607.8 million compared to $671.5 million for the corresponding period in 2010. The net decrease in fuel and purchased power expenses was due to a $35.6 million decrease in the average cost of purchased power, a $26.1 million decrease in the average cost of fuel, and a $2.0 million net decrease related to total KWHs generated and purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Fuel Cost Recovery” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter     Third Quarter     Percent     Year-to-Date     Year-to-Date     Percent  
Average Cost   2011     2010     Change     2011     2010     Change  
    (cents per net KWH)             (cents per net KWH)          
 
Fuel
    4.79       5.09       (5.9)       4.77       5.04       (5.4)  
Purchased power
    4.70       7.93       (40.7)       4.86       5.99       (18.9)  
 
In the third quarter 2011, fuel expense was $220.3 million compared to $237.0 million for the corresponding period in 2010. The decrease was primarily due to a 24.0% decrease in KWHs generated from Gulf Power’s coal-fired resources and a 7.5% decrease in the average cost of natural gas per KWH generated.
For year-to-date 2011, fuel expense was $530.8 million compared to $585.2 million for the corresponding period in 2010. The decrease was primarily due to a 21.0% decrease in KWHs generated from Gulf Power’s coal-fired resources and a 15.3% decrease in the average cost of natural gas per KWH generated.
Non-Affiliates
In the third quarter 2011, purchased power expense from non-affiliates was $20.0 million compared to $12.7 million for the corresponding period in 2010. The increase was primarily due to a 168.8% increase in the volume of KWHs purchased, partially offset by a 27.4% decrease in the average cost per KWH purchased.
For year-to-date 2011, purchased power expense from non-affiliates was $37.9 million compared to $34.6 million for the corresponding period in 2010. The increase was primarily due to a 36.4% increase in the volume of KWHs purchased, partially offset by a 12.8% decrease in the average cost per KWH purchased.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.
Affiliates
In the third quarter 2011, purchased power expense from affiliates was $10.0 million compared to $20.3 million for the corresponding period in 2010. The decrease was primarily due to a 61.6% decrease in the volume of KWHs purchased, partially offset by a 26.7% increase in the average cost per KWH purchased.
For year-to-date 2011, purchased power expense from affiliates was $39.1 million compared to $51.7 million for the corresponding period in 2010. The decrease was primarily due to a 25.0% decrease in the average cost per KWH purchased.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$6.9   10.4   $25.0   12.4
 
In the third quarter 2011, other operations and maintenance expenses were $74.1 million compared to $67.2 million for the corresponding period in 2010. The increase was primarily due to increases in expenses for labor, routine and planned outage maintenance at generation facilities, energy service projects, and marketing programs. The increased expenses from energy service projects did not have a material impact on earnings since they were offset by associated revenues.
For year-to-date 2011, other operations and maintenance expenses were $227.2 million compared to $202.2 million for the corresponding period in 2010. The increase was primarily due to increases in expenses for routine and planned outage maintenance at generation facilities, labor, and energy service projects. The increased expenses from energy service projects did not have a material impact on earnings since they were offset by associated revenues.
Depreciation and Amortization
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.3)   (4.0)   $6.1   6.7
 
In the third quarter 2011, depreciation and amortization was $32.7 million compared to $34.0 million for the corresponding period in 2010. The decrease was primarily due to new depreciation rates implemented in August 2010, partially offset by net additions to transmission and distribution facilities.
For year-to-date 2011, depreciation and amortization was $96.7 million compared to $90.6 million for the corresponding period in 2010. The increase was primarily due to the addition of environmental control projects and other net additions to transmission and distribution facilities.
Allowance for Equity Funds Used During Construction
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.0   70.9   $2.6   57.4
 
In the third quarter 2011, AFUDC equity was $2.4 million compared to $1.4 million for the corresponding period in 2010. For year-to-date 2011, AFUDC equity was $7.1 million compared to $4.5 million for the corresponding period in 2010. The increases were primarily due to construction of environmental control projects at generating facilities.
Interest Expense, Net of Amounts Capitalized
             

Third Quarter 2011 vs. Third Quarter 2010
 
Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.4   10.1   $4.9   12.9
 
In the third quarter 2011, interest expense, net of amounts capitalized was $15.2 million compared to $13.8 million for the corresponding period in 2010. For year-to-date 2011, interest expense, net of amounts capitalized was $43.2 million compared to $38.3 million for the corresponding period in 2010. The increases were primarily due to increased long-term debt levels resulting from the issuance of additional senior notes.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
             
Third Quarter 2011 vs. Third Quarter 2010
  Year-to-Date 2011 vs. Year-to-Date 2010
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.2)   (0.5)   $(7.6)   (12.8)
 
In the third quarter 2011, income taxes were $25.5 million compared to $25.7 million for the corresponding period in 2010. For year-to-date 2011, income taxes were $52.5 million compared to $60.1 million for the corresponding period in 2010. The decreases were primarily due to lower pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s 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. Future earnings 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, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Changes in economic conditions impact sales for Gulf 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Gulf Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Gulf Power in Item 7 of the Form 10-K for additional information regarding the proposed coal combustion byproducts rule. Although its analysis is preliminary, Gulf Power estimates the aggregate capital costs for compliance with these rules to be $1.9 billion through 2020 if the rules are adopted as proposed. Included in this amount is $373 million of estimated expenditures included in Gulf Power’s 2011-2013 base level capital budget described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein for additional information. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Gulf Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

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Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Gulf Power in Item 7 and Note 3 of the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Gulf Power in Item 7 and Note 3 of the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Gulf Power, and includes many of the same defendants that were involved in the earlier case. Gulf Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality.
On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Gulf Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.
On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The States of Alabama, Florida, Georgia, and Mississippi are subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program. The States of Alabama and Georgia are subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the States of Alabama, Florida, Georgia, and Mississippi. The rule could have significant effects on Gulf Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Gulf Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Gulf Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Gulf Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Florida PSC Matters
Retail Base Rate Case
On July 8, 2011, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates to the extent necessary to generate additional gross annual revenues in the amount of $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012. Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2012 through December 31, 2012 which serves as the test year.
On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.
The ultimate outcome of this matter cannot be determined at this time.
General
On November 1, 2011, the Florida PSC approved Gulf Power’s annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2012. The net effect of the approved changes is a 1.1% rate decrease for residential customers using 1,000 KWHs per month. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – General,” respectively, in Item 8 of the Form 10-K for additional information.
Fuel Cost Recovery
Gulf Power has established fuel cost recovery rates approved by the Florida PSC. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the fuel cost recovery factor is being requested.
In previous years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. Under recovered fuel costs at September 30, 2011 totaled $7.5 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. 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, any change in the billing factor will have no significant effect on Gulf Power’s revenues or net income, but will affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.
Purchased Power Capacity Recovery
Gulf Power has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected purchased power capacity cost over or under recovery balance at year-end exceeds 10% of the projected purchased power capacity revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the purchased power capacity cost recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on August 19, 2011, but no adjustment to the 2011 factor was requested.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Over recovered purchased power capacity costs at September 30, 2011 totaled $3.5 million compared to $4.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein. Purchased power capacity 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, any change in the billing factor will have no significant effect on Gulf Power’s revenues or net income, but will affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Purchased Power Capacity Recovery,” respectively, in Item 8 of the Form 10-K for additional information.
Environmental Cost Recovery
In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.
Over recovered environmental costs at September 30, 2011 totaled $16.9 million compared to $10.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Cost Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.
Energy Conservation Cost Recovery
Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.
The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.
See BUSINESS under “Rate Matters – Integrated Resource Planning – Gulf Power” in Item 1 of the Form 10-K for a discussion of Gulf Power’s 10-year site plan filed on an annual basis with the Florida PSC.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Tax Matters
Legislation
On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
In September 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, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (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 will have a positive impact on the future cash flows of Gulf Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Gulf Power estimates the potential increased cash flow for 2011 to be between approximately $40 million and $50 million. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities 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, 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 Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Gulf Power’s financial condition remained stable at September 30, 2011. Gulf Power 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.
Net cash provided from operating activities totaled $325.3 million for the first nine months of 2011 compared to $255.0 million for the corresponding period in 2010. The $70.3 million increase was primarily due to a $41.6 million increase from prepaid income taxes primarily related to bonus depreciation and a $27.9 million increase related to payments from customer receivables. Net cash used for investing activities totaled $243.1 million in the first nine months of 2011 compared to $220.6 million for the corresponding period in 2010. The $22.4 million increase in cash used was primarily due to gross property additions. Net cash used for financing activities totaled $81.3 million for the first nine months of 2011 compared to $59.3 million provided from financing activities for the corresponding period in 2010. The $140.6 million change was primarily due to a $175.0 million decrease in issuances of pollution control revenue bonds and a $110.0 million increase in redemptions of other long-term debt in 2011, partially offset by $139.9 million fewer redemptions of senior notes in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2011 include a net increase of $161.3 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of $125.0 million in senior notes; an increase of $71.7 million in accumulated deferred income taxes related to property; the issuance of common stock to Southern Company for $50 million; a decrease of $110.0 million in securities due within one year; and a decrease of $36.1 million in prepaid expenses, primarily related to prepaid income taxes.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. There are no requirements through September 30, 2012 to fund maturities of long-term debt.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The construction program of Gulf Power is estimated to include a base level investment of $381.5 million, $395.5 million, and $384.1 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. In addition, Gulf Power estimates that potential incremental investments to comply with anticipated new environmental regulations are up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Gulf Power estimates the potential investments for new environmental regulations may exceed these estimates. The construction program is 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; storm impacts; 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; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans 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, short-term debt, security issuances, a long-term bank note, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at September 30, 2011 cash and cash equivalents of approximately $17.3 million and unused committed credit arrangements with banks of $240 million. During the third quarter, Gulf Power reviewed its lines of credit program and made changes resulting in a net decrease of $40 million. The changes also included the renewal of two lines of credit totaling $60 million for an extended term of three years. Of the unused credit arrangements, $20 million expire in 2011, $55 million expire in 2012, and $165 million expire in 2014. Of the credit arrangements expiring on or before September 30, 2012, $55 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. During the third quarter 2011, Gulf Power repaid a $30 million draw on a line of credit. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power 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 Gulf Power and other Southern Company subsidiaries. At September 30, 2011, Gulf Power had $33 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.2% per annum. During the third quarter 2011, Gulf Power had an average of $58 million of short-term borrowings outstanding with a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $99 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Gulf Power 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 to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $538 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Gulf Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2011 were as follows:
                 
    Third Quarter   Year-to-Date
    2011   2011
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (9 )   $ (11 )
Contracts realized or settled
    3       8  
Current period changes(a)
    (11 )     (14 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (17 )   $ (17 )
 
 
(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 three and nine months ended September 30, 2011 was a decrease of $8 million and a decrease of $6 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Gulf Power had a net hedge volume of 26.1 million mmBtu with a weighted average contract cost approximately $0.67 per mmBtu above market prices, compared to 22.9 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.42 per mmBtu above market prices and compared to 19.6 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $0.67 per mmBtu above market prices.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Regulatory hedges relate to Gulf Power’s fuel-hedging program 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 clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.
Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:
                                 
    September 30, 2011
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
 
 
  (in millions)
Level 1
  $     $     $     $  
Level 2
    (17 )     (10 )     (6 )     (1 )
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (17 )   $ (10 )   $ (6 )   $ (1 )
 
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 Gulf Power. 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.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and Note 1 under “Financial Instruments” and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2011, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.
In May 2011, Gulf Power issued $125 million aggregate principal amount of Series 2011A 5.75% Senior Notes due June 1, 2051. The net proceeds from the sale of the Series 2011A Senior Notes were used to repay a $110 million bank note, to repay a portion of Gulf Power’s outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power’s continuous construction program.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 233,298     $ 230,977     $ 620,777     $ 620,658  
Wholesale revenues, non-affiliates
    78,147       78,409       215,811       223,499  
Wholesale revenues, affiliates
    9,804       13,025       25,407       31,636  
Other revenues
    4,517       4,672       13,088       11,749  
 
                       
Total operating revenues
    325,766       327,083       875,083       887,542  
 
                       
Operating Expenses:
                               
Fuel
    157,961       154,607       402,689       388,979  
Purchased power, non-affiliates
    2,314       2,547       4,660       7,666  
Purchased power, affiliates
    8,504       10,902       36,721       60,113  
Other operations and maintenance
    65,851       65,953       200,730       205,055  
Depreciation and amortization
    19,668       20,106       59,876       57,567  
Taxes other than income taxes
    18,297       17,935       53,029       53,568  
 
                       
Total operating expenses
    272,595       272,050       757,705       772,948  
 
                       
Operating Income
    53,171       55,033       117,378       114,594  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    7,291       1,490       15,413       2,018  
Interest income
    167       49       910       122  
Interest expense, net of amounts capitalized
    (3,856 )     (4,886 )     (15,401 )     (17,011 )
Other income (expense), net
    257       1,099       (759 )     3,272  
 
                       
Total other income and (expense)
    3,859       (2,248 )     163       (11,599 )
 
                       
Earnings Before Income Taxes
    57,030       52,785       117,541       102,995  
Income taxes
    18,578       18,759       38,323       37,631  
 
                       
Net Income
    38,452       34,026       79,218       65,364  
Dividends on Preferred Stock
    433       433       1,299       1,299  
 
                       
Net Income After Dividends on Preferred Stock
  $ 38,019     $ 33,593     $ 77,919     $ 64,065  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2011     2010     2011     2010  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred Stock
  $ 38,019     $ 33,593     $ 77,919     $ 64,065  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(5,630), $4, $(5,624), and $8, respectively
    (9,090 )     7       (9,079 )     13  
 
                       
Comprehensive Income
  $ 28,929     $ 33,600     $ 68,840     $ 64,078  
 
                       
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2011     2010  
    (in thousands)  
Operating Activities:
               
Net income
  $ 79,218     $ 65,364  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    64,329       60,959  
Deferred income taxes
    35,225       (4,557 )
Investment tax credits received
    51,761       14,352  
Allowance for equity funds used during construction
    (15,413 )     (2,018 )
Pension, postretirement, and other employee benefits
    3,327       6,657  
Generation construction screening costs
          (50,554 )
Stock based compensation expense
    1,302       1,053  
Other, net
    (7,642 )     (720 )
Changes in certain current assets and liabilities —
               
-Receivables
    (5,295 )     (21,003 )
-Fossil fuel stock
    2,345       10,163  
-Materials and supplies
    (1,442 )     (222 )
-Prepaid income taxes
    (18,762 )      
-Other current assets
    2,295       (2,503 )
-Accounts payable
    21,711       25,819  
-Accrued taxes
    (3,751 )     7,630  
-Accrued compensation
    (4,514 )     427  
-Over recovered regulatory clause revenues
    (17,754 )     14,939  
-Other current liabilities
    (296 )     (442 )
 
           
Net cash provided from operating activities
    186,644       125,344  
 
           
Investing Activities:
               
Property additions
    (605,710 )     (125,980 )
Cost of removal, net of salvage
    (6,931 )     (7,613 )
Construction payables
    70,909       6,903  
Capital grant proceeds
    139,921        
Distribution of restricted cash
    50,000        
Other investing activities
    (3,399 )     (6,693 )
 
           
Net cash used for investing activities
    (355,210 )     (133,383 )
 
           
Financing Activities:
               
Proceeds —
               
Capital contributions from parent company
    199,782       3,920  
Other long-term debt issuances
    115,000       125,000  
Redemptions —
               
Capital leases
    (1,067 )     (988 )
Other long-term debt
    (130,000 )      
Payment of preferred stock dividends
    (1,299 )     (1,299 )
Payment of common stock dividends
    (56,625 )     (51,450 )
Other financing activities
    (377 )     (614 )
 
           
Net cash provided from financing activities
    125,414       74,569  
 
           
Net Change in Cash and Cash Equivalents
    (43,152 )     66,530  
Cash and Cash Equivalents at Beginning of Period
    160,779       65,025  
 
           
Cash and Cash Equivalents at End of Period
  $ 117,627     $ 131,555  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $5,136 and $1,482 capitalized for 2011 and 2010, respectively)
  $ 13,956     $ 16,726  
Income taxes (net of refunds)
    (33,276 )     11,345  
Noncash transactions — accrued property additions at end of period
    109,732       10,592  
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At September 30,     At December 31,  
Assets   2011     2010  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 117,627     $ 160,779  
Restricted cash and cash equivalents
          50,000  
Receivables —
               
Customer accounts receivable
    45,269       37,532  
Unbilled revenues
    28,753       31,010  
Other accounts and notes receivable
    7,765       11,220  
Affiliated companies
    22,282       17,837  
Accumulated provision for uncollectible accounts
    (709 )     (638 )
Fossil fuel stock, at average cost
    109,895       112,240  
Materials and supplies, at average cost
    30,114       28,671  
Other regulatory assets, current
    59,143       63,896  
Prepaid income taxes
    71,749       59,596  
Other current assets
    28,602       19,057  
 
           
Total current assets
    520,490       591,200  
 
           
Property, Plant, and Equipment:
               
In service
    2,445,523       2,392,477  
Less accumulated provision for depreciation
    988,073       971,559  
 
           
Plant in service, net of depreciation
    1,457,450   &nbs