SOUTHERN COMPANY
Table of Contents

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, 2009
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 35291    
 
  (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    
 
       
0-2429
  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, 2009
The Southern Company
  Par Value $5 Per Share     800,211,378  
Alabama Power Company
  Par Value $40 Per Share     28,850,000  
Georgia Power Company
  Without Par Value     9,261,500  
Gulf Power Company
  Without Par Value     3,142,717  
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.

2


 

INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2009
             
        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
       
           
        9  
        10  
        11  
        13  
        14  
           
        37  
        37  
        38  
        39  
        41  
           
        59  
        59  
        60  
        61  
        63  
           
        81  
        81  
        82  
        83  
        85  
           
        102  
        102  
        103  
        104  
        106  
           
        125  
        125  
        126  
        127  
        129  
        142  
Item 3.       35  
Item 4.       35  
Item 4T.       35  

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2009
             
        Page
        Number
PART II — OTHER INFORMATION
   
 
       
Item 1.         173
Item 1A.         173
Item 2.  
Unregistered Sales of Equity Securities and Use of Proceeds
  Inapplicable
Item 3.  
Defaults Upon Senior Securities
  Inapplicable
Item 4.  
Submission of Matters to a Vote of Security Holders
  Inapplicable
Item 5.  
Other Information
  Inapplicable
Item 6.         174
          177

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DEFINITIONS
     
Term   Meaning
2007 Retail Rate Plan
  Georgia Power’s retail rate plan for the years 2008 through 2010
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
FASB
  Financial Accounting Standards Board
FERC
  Federal Energy Regulatory Commission
Fitch
  Fitch Ratings, Inc.
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, 2008 and, with respect to Southern Company, the subsequently revised audited financial statements included in the Current Report on Form 8-K filed May 8, 2009
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
IRS
  Internal Revenue Service
KWH
  Kilowatt-hour
LIBOR
  London Interbank Offered Rate
Mirant
  Mirant Corporation
Mississippi Power
  Mississippi Power Company
mmBtu
  Million British thermal unit
Moody’s
  Moody’s Investors Service
MW
  Megawatt
MWH
  Megawatt-hour
NRC
  Nuclear Regulatory Commission
NSR
  New Source Review
OCI
  Other Comprehensive Income
PEP
  Performance Evaluation Plan
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 ECR
  Alabama Power’s energy cost recovery rate mechanism
registrants
  Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS
  Southern Company Services, Inc.
SEC
  Securities and Exchange Commission
Southern Company
  The Southern Company
Southern Company system
  Southern Company, the traditional operating companies, Southern Power, and other subsidiaries

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DEFINITIONS
(continued)
     
Term   Meaning
SouthernLINC Wireless
  Southern Communications Services, Inc.
Southern Nuclear
  Southern Nuclear Operating Company, Inc.
Southern Power
  Southern Power Company
Standard and Poor’s
  Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.
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, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, retail return on equity projections, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project, unrecognized tax benefits related to leveraged lease transactions, impact of the American Recovery and Reinvestment Act of 2009, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
  the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
  current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, IRS audits, and Mirant matters;
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
  variations in demand for electricity, including those relating to weather, the general economy, 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;
  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 storm restoration cost recovery;
  regulatory approvals related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals;
  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 neighboring utilities and other wholesale customers;
  the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
  interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
  the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
  catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian or other influenza, or other similar occurrences;
  the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
  the effect of accounting pronouncements issued periodically by standard setting bodies; and
  other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
Each registrant expressly disclaims 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,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 3,997,659     $ 4,478,292     $ 10,355,330     $ 10,933,784  
Wholesale revenues
    519,122       774,847       1,408,286       1,880,311  
Other electric revenues
    139,869       142,459       391,070       413,811  
Other revenues
    24,832       30,901       78,267       96,690  
 
                       
Total operating revenues
    4,681,482       5,426,499       12,232,953       13,324,596  
 
                       
Operating Expenses:
                               
Fuel
    1,733,527       2,152,828       4,588,932       5,226,845  
Purchased power
    166,791       378,259       407,623       668,423  
Other operations and maintenance
    820,889       908,404       2,523,184       2,720,219  
MC Asset Recovery litigation settlement
                202,000        
Depreciation and amortization
    332,117       367,014       1,099,216       1,069,644  
Taxes other than income taxes
    212,882       215,298       620,851       602,612  
 
                       
Total operating expenses
    3,266,206       4,021,803       9,441,806       10,287,743  
 
                       
Operating Income
    1,415,276       1,404,696       2,791,147       3,036,853  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    51,061       35,541       141,173       111,612  
Interest income
    6,013       9,744       17,791       20,737  
Equity in income (losses) of unconsolidated subsidiaries
    (34 )     4,704       (330 )     6,129  
Leveraged lease income (losses)
    6,578       6,343       24,695       (53,611 )
Gain on disposition of lease termination
                26,300        
Loss on extinguishment of debt
                (17,184 )      
Interest expense, net of amounts capitalized
    (226,345 )     (219,066 )     (684,902 )     (665,123 )
Other income (expense), net
    (10,432 )     (10,816 )     (26,963 )     (14,385 )
 
                       
Total other income and (expense)
    (173,159 )     (173,550 )     (519,420 )     (594,641 )
 
                       
Earnings Before Income Taxes
    1,242,117       1,231,146       2,271,727       2,442,212  
Income taxes
    435,947       434,515       828,833       837,605  
 
                       
Consolidated Net Income
    806,170       796,631       1,442,894       1,604,607  
Dividends on Preferred and Preference Stock of Subsidiaries
    16,195       16,195       48,585       48,585  
 
                       
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
  $ 789,975     $ 780,436     $ 1,394,309     $ 1,556,022  
 
                       
Common Stock Data:
                               
Earnings per share (EPS) -
                               
Basic EPS
  $ 0.99     $ 1.01     $ 1.77     $ 2.02  
Diluted EPS
  $ 0.99     $ 1.00     $ 1.76     $ 2.01  
Average number of shares of common stock outstanding (in thousands)
                               
Basic
    798,418       772,622       789,675       769,298  
Diluted
    800,178       776,903       791,259       773,451  
Cash dividends paid per share of common stock
  $ 0.4375     $ 0.4200     $ 1.2950     $ 1.2425  
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,  
    2009     2008  
    (in thousands)  
Operating Activities:
               
Consolidated net income
  $ 1,442,894     $ 1,604,607  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    1,310,854       1,265,696  
Deferred income taxes and investment tax credits
    (14,565 )     46,006  
Deferred revenues
    (40,781 )     94,924  
Allowance for equity funds used during construction
    (141,173 )     (111,612 )
Equity in income (losses) of unconsolidated subsidiaries
    330       (6,129 )
Leveraged lease income (losses)
    (24,695 )     53,611  
Gain on disposition of lease termination
    (26,300 )      
Loss on extinguishment of debt
    17,184        
Pension, postretirement, and other employee benefits
    42,775       75,965  
Stock option expense
    20,850       17,730  
Hedge settlements
    (16,167 )     17,289  
Other, net
    10,036       (56,200 )
Changes in certain current assets and liabilities —
               
-Receivables
    319,286       (522,004 )
-Fossil fuel stock
    (361,520 )     (112,328 )
-Materials and supplies
    (40,811 )     (25,347 )
-Other current assets
    (50,977 )     (33,896 )
-Accounts payable
    (210,459 )     (45,079 )
-Accrued taxes
    238,988       409,684  
-Accrued compensation
    (273,349 )     (86,436 )
-Other current liabilities
    157,384       49,651  
 
           
Net cash provided from operating activities
    2,359,784       2,636,132  
 
           
Investing Activities:
               
Property additions
    (3,179,009 )     (2,860,118 )
Investment in restricted cash from pollution control revenue bonds
    (49,528 )     (5,454 )
Distribution of restricted cash from pollution control revenue bonds
    90,088       46,782  
Nuclear decommissioning trust fund purchases
    (1,066,688 )     (581,171 )
Nuclear decommissioning trust fund sales
    1,019,401       574,291  
Proceeds from property sales
    339,911       5,718  
Cost of removal, net of salvage
    (85,022 )     (74,714 )
Change in construction payables
    110,265       (8,703 )
Other investing activities
    (35,766 )     (76,402 )
 
           
Net cash used for investing activities
    (2,856,348 )     (2,979,771 )
 
           
Financing Activities:
               
Increase in notes payable, net
    118,124       62,302  
Proceeds —
               
Long-term debt issuances
    2,216,010       2,416,035  
Common stock issuances
    668,529       381,200  
Redemptions —
               
Long-term debt
    (1,229,484 )     (769,789 )
Redeemable preferred stock
          (125,000 )
Payment of common stock dividends
    (1,018,928 )     (954,438 )
Payment of dividends on preferred and preference stock of subsidiaries
    (48,675 )     (49,497 )
Other financing activities
    (18,732 )     (11,705 )
 
           
Net cash provided from financing activities
    686,844       949,108  
 
           
Net Change in Cash and Cash Equivalents
    190,280       605,469  
Cash and Cash Equivalents at Beginning of Period
    416,581       200,550  
 
           
Cash and Cash Equivalents at End of Period
  $ 606,861     $ 806,019  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $59,849 and $54,404 capitalized for 2009 and 2008, respectively)
  $ 589,919     $ 575,597  
Income taxes (net of refunds)
  $ 644,541     $ 489,600  
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   2009     2008  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 606,861     $ 416,581  
Restricted cash and cash equivalents
    66,403       102,537  
Receivables —
               
Customer accounts receivable
    1,234,810       1,053,674  
Unbilled revenues
    394,815       320,439  
Under recovered regulatory clause revenues
    416,805       646,318  
Other accounts and notes receivable
    270,348       301,028  
Accumulated provision for uncollectible accounts
    (29,044 )     (26,326 )
Fossil fuel stock, at average cost
    1,373,037       1,018,314  
Materials and supplies, at average cost
    795,622       756,746  
Vacation pay
    135,061       140,283  
Prepaid expenses
    372,951       301,570  
Other regulatory assets, current
    193,710       275,424  
Other current assets
    50,554       51,044  
 
           
Total current assets
    5,881,933       5,357,632  
 
           
Property, Plant, and Equipment:
               
In service
    52,326,502       50,618,219  
Less accumulated depreciation
    18,985,998       18,285,800  
 
           
Plant in service, net of depreciation
    33,340,504       32,332,419  
Nuclear fuel, at amortized cost
    536,191       510,274  
Construction work in progress
    4,265,084       3,035,795  
 
           
Total property, plant, and equipment
    38,141,779       35,878,488  
 
           
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,060,161       864,396  
Leveraged leases
    606,165       897,338  
Miscellaneous property and investments
    228,594       226,757  
 
           
Total other property and investments
    1,894,920       1,988,491  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,033,025       972,781  
Unamortized debt issuance expense
    209,607       207,763  
Unamortized loss on reacquired debt
    260,077       270,919  
Deferred under recovered regulatory clause revenues
    317,780       606,483  
Other regulatory assets, deferred
    2,404,534       2,636,217  
Other deferred charges and assets
    380,552       428,432  
 
           
Total deferred charges and other assets
    4,605,575       5,122,595  
 
           
Total Assets
  $ 50,524,207     $ 48,347,206  
 
           
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   2009     2008  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 412,295     $ 616,415  
Notes payable
    1,064,694       953,437  
Accounts payable
    1,158,560       1,249,694  
Customer deposits
    325,035       302,495  
Accrued taxes —
               
Accrued income taxes
    176,299       195,922  
Unrecognized tax benefits
    160,649       131,641  
Other accrued taxes
    423,540       396,206  
Accrued interest
    227,821       195,500  
Accrued vacation pay
    168,955       178,519  
Accrued compensation
    191,139       446,718  
Liabilities from risk management activities
    147,464       260,977  
Other regulatory liabilities, current
    422,199       78,360  
Other current liabilities
    297,364       220,351  
 
           
Total current liabilities
    5,176,014       5,226,235  
 
           
Long-term Debt
    18,010,235       16,816,438  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    6,350,882       6,080,104  
Deferred credits related to income taxes
    257,581       259,156  
Accumulated deferred investment tax credits
    435,785       455,398  
Employee benefit obligations
    2,023,883       2,057,424  
Asset retirement obligations
    1,235,309       1,182,769  
Other cost of removal obligations
    1,048,279       1,320,558  
Other regulatory liabilities, deferred
    241,160       261,970  
Other deferred credits and liabilities
    301,167       329,534  
 
           
Total deferred credits and other liabilities
    11,894,046       11,946,913  
 
           
Total Liabilities
    35,080,295       33,989,586  
 
           
Redeemable Preferred Stock of Subsidiaries
    374,496       374,496  
 
           
Stockholders’ Equity:
               
Common Stockholders’ Equity:
               
Common stock, par value $5 per share —
               
Authorized — 1 billion shares
               
Issued — September 30, 2009: 800,693,706 Shares;
               
— December 31, 2008: 777,615,751 Shares
               
Treasury — September 30, 2009: 482,328 Shares;
               
— December 31, 2008: 423,477 Shares
               
Par value
    4,003,446       3,888,041  
Paid-in capital
    2,469,185       1,892,802  
Treasury, at cost
    (14,042 )     (12,279 )
Retained earnings
    7,987,893       7,611,977  
Accumulated other comprehensive loss
    (84,433 )     (104,784 )
 
           
Total Common Stockholders’ Equity
    14,362,049       13,275,757  
Preferred and Preference Stock of Subsidiaries
    707,367       707,367  
 
           
Total Stockholders’ Equity
    15,069,416       13,983,124  
 
           
Total Liabilities and Stockholders’ Equity
  $ 50,524,207     $ 48,347,206  
 
           
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,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Consolidated Net Income
  $ 806,170     $ 796,631     $ 1,442,894     $ 1,604,607  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(1,356), $11,996, $(2,338), and $579, respectively
    (2,151 )     18,603       (3,815 )     690  
Reclassification adjustment for amounts included in net income, net of tax of $4,610, $1,730, $13,073, and $5,879, respectively
    7,339       2,709       20,807       9,217  
Marketable securities:
                               
Change in fair value, net of tax of $(1,056), $163, $239, and $(2,293), respectively
    (1,359 )     86       2,310       (3,940 )
Reclassification adjustment for amounts included in net income, net of tax of $-, $3, $-, and $3, respectively
          4             4  
Pension and other post retirement benefit plans:
                               
Reclassification adjustment for amounts included in net income, net of tax of $222, $237, $665, and $773, respectively
    350       376       1,049       1,258  
 
                       
Total other comprehensive income (loss)
    4,179       21,778       20,351       7,229  
 
                       
Dividends on preferred and preference stock of subsidiaries
    (16,195 )     (16,195 )     (48,585 )     (48,585 )
 
                       
Comprehensive Income
  $ 794,154     $ 802,214     $ 1,414,660     $ 1,563,251  
 
                       
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 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008
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 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$9.6   1.2   $(161.7)   (10.4)
 
Southern Company’s third quarter 2009 net income after dividends on preferred and preference stock of subsidiaries was $790.0 million ($0.99 per share) compared to $780.4 million ($1.01 per share) for the corresponding period in 2008. The increase for the third quarter 2009 when compared to the corresponding period in 2008 was primarily the result of an increase in revenues from customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, lower operations and maintenance expenses, amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, and an increase in allowance for equity funds used during construction (AFUDC), which is not taxable. The increase for the third quarter 2009 was partially offset by a decrease in revenues from lower KWH demand by industrial customers, a decrease in revenues from market-response rates to large commercial and industrial customers, and unfavorable weather as compared to the corresponding period in 2008.
Southern Company’s year-to-date 2009 net income after dividends on preferred and preference stock of subsidiaries was $1.39 billion ($1.77 per share) compared to $1.56 billion ($2.02 per share) for the corresponding period in 2008. The decrease for year-to-date 2009 when compared to the corresponding period in 2008 was primarily the result of a litigation settlement with MC Asset Recovery, LLC (MC Asset Recovery), a decrease in revenues from lower KWH demand by residential and industrial customers, a decrease in revenues from market-response rates to large commercial and industrial customers, unfavorable weather, higher depreciation and amortization, and higher interest expense. The decrease for year-to-date 2009 was partially offset by an increase in revenues from customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, lower operations and maintenance expenses, an increase in AFUDC, which is not taxable, a 2008 charge related to tax treatment of leveraged lease investments, and a gain on the early termination of two international leveraged lease investments.

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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 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(480.6)   (10.7)   $(578.5)   (5.3)
 
In the third quarter 2009, retail revenues were $4.00 billion compared to $4.48 billion for the corresponding period in 2008.
For year-to-date 2009, retail revenues were $10.36 billion compared to $10.93 billion for the corresponding period in 2008.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2009   2009
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 4,478.3             $ 10,933.8          
Estimated change in —
                               
Rates and pricing
    4.5       0.1       92.3       0.8  
Sales growth (decline)
    (54.1 )     (1.2 )     (195.3 )     (1.8 )
Weather
    (39.6 )     (0.9 )     (35.2 )     (0.3 )
Fuel and other cost recovery
    (391.4 )     (8.7 )     (440.3 )     (4.0 )
 
Retail – current year
  $ 3,997.7       (10.7 )%   $ 10,355.3       (5.3 )%
 
Revenues associated with changes in rates and pricing increased in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008 primarily as a result of an increase in revenues from customer charges at Alabama Power and increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers.
Revenues attributable to changes in sales declined in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008 due to decreases in weather-adjusted retail KWH sales of 3.4% and 5.3%, respectively, resulting primarily from recessionary economic conditions. For the third quarter 2009, weather-adjusted residential KWH sales remained flat, weather-adjusted commercial KWH sales decreased 2.1%, and weather-adjusted industrial KWH sales decreased 9.3%. For year-to-date 2009, weather-adjusted residential KWH sales remained flat, weather-adjusted commercial KWH sales decreased 1.3%, and weather-adjusted industrial KWH sales decreased 14.6%. Reduced demand in the primary metals, fabricated metal, chemical, and textiles sectors, as well as reduced demand in the stone, clay, and glass sector, contributed most significantly to the decreases in weather-adjusted industrial KWH sales in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008. While weather-adjusted industrial KWH sales for the third quarter 2009 decreased 9.3% when compared to the corresponding period in 2008, weather-adjusted industrial KWH sales increased 12.0% when compared to the second quarter 2009.
Revenues resulting from changes in weather decreased in the third quarter and for year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and other cost recovery revenues decreased in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008. 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.
Wholesale Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(255.7)   (33.0)   $(472.0)   (25.1)
 
In the third quarter 2009, wholesale revenues were $519.1 million compared to $774.8 million for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $258.8 million in the third quarter 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $3.1 million in the third quarter 2009 when compared to the corresponding period in 2008. The increase was primarily the result of additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009.
For year-to-date 2009, wholesale revenues were $1.41 billion compared to $1.88 billion for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $484.8 million for year-to-date 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $12.8 million for year-to-date 2009 when compared to the corresponding period in 2008. The increase was primarily the result of additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower energy prices and reduced margins on short-term opportunity sales when compared to the corresponding period in 2008.
Short-term opportunity sales are made at market-based rates that generally provide a margin above Southern Company’s variable cost to produce the energy.
Other Electric Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.6)   (1.8)   $(22.7)   (5.5)
 
In the third quarter 2009, other electric revenues were $139.9 million compared to $142.5 million for the corresponding period in 2008. The decrease when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, other electric revenues were $391.1 million compared to $413.8 million for the corresponding period in 2008. The decrease was primarily the result of a $39.6 million decrease in co-generation revenues due to lower gas prices and a decline in sales volume, partially offset by a $7.3 million increase in customer fees. Revenues from co-generation are generally offset by related expenses 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
Other Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(6.1)   (19.6)   $(18.4)   (19.1)
 
In the third quarter 2009, other revenues were $24.8 million compared to $30.9 million for the corresponding period in 2008. The decrease was primarily the result of a $5.9 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.
For year-to-date 2009, other revenues were $78.3 million compared to $96.7 million for the corresponding period in 2008. The decrease was primarily the result of an $18.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2009   Year-to-Date 2009
    vs.   vs.
    Third Quarter 2008   Year-to-Date 2008
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ (419.3 )     (19.5 )   $ (637.9 )     (12.2 )
Purchased power
    (211.5 )     (55.9 )     (260.8 )     (39.0 )
                           
Total fuel and purchased power expenses
  $ (630.8 )           $ (898.7 )        
                           
* 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.
In the third quarter 2009, fuel and purchased power expenses were $1.90 billion compared to $2.53 billion for the corresponding period in 2008. The decrease was primarily the result of a $317.9 million net decrease related to total KWHs generated and purchased and a $312.9 million net decrease in the average cost of fuel and purchased power when compared to the corresponding period in 2008. The net decrease in the average cost of fuel and purchased power for the third quarter 2009 resulted primarily from lower gas prices and a significant increase in hydro generation due to increased rainfall when compared to the corresponding period in 2008.
For year-to-date 2009, fuel and purchased power expenses were $5.00 billion compared to $5.90 billion for the corresponding period in 2008. The decrease was primarily the result of a $602.8 million net decrease related to total KWHs generated and purchased and a $295.9 million net decrease in the average cost of fuel and purchased power when compared to the corresponding period in 2008. The net decrease in the average cost of fuel and purchased power for year-to-date 2009 resulted primarily from lower gas prices and a significant increase in hydro generation due to increased rainfall when compared to the corresponding period in 2008.
Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not affect net income. See FUTURE EARNINGS POTENTIAL – “FERC and 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.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Southern Company’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter   Percent   Year-to-Date   Year-to-Date   Percent
Average Cost   2009   2008   Change   2009   2008   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    3.42       3.96       (13.6 )     3.39       3.46       (2.0 )
Purchased power
    8.00       9.70       (17.5 )     6.20       9.02       (31.3 )
 
Energy purchases will vary depending on demand for energy within the Southern Company 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.
Other Operations and Maintenance Expenses
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(87.5)   (9.6)   $(197.0)   (7.2)
 
In the third quarter 2009, other operations and maintenance expenses were $820.9 million compared to $908.4 million for the corresponding period in 2008. The decrease was primarily the result of a $32.7 million decrease in fossil, hydro, and nuclear expenses mainly due to less planned spending on outages and maintenance, as well as other cost containment activities, which were the result of efforts to offset the effects of the recessionary economy; a $16.1 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses; a $9.6 million decrease in expenses related to customer service and sales; a $4.3 million decrease in expenses related to lower sales and fewer subscribers at SouthernLINC Wireless; and a $4.1 million decrease in administrative and general expenses mainly due to a decrease in accrued expenses for the litigation and workers’ compensation reserve.
For year-to-date 2009, other operations and maintenance expenses were $2.52 billion compared to $2.72 billion for the corresponding period in 2008. The decrease was primarily the result of an $80.0 million decrease in fossil, hydro, and nuclear expenses mainly due to less planned spending on outages and maintenance, as well as other cost containment activities, which were the result of efforts to offset the effects of the recessionary economy; a $57.1 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses, as well as other cost containment activities; a $16.5 million decrease in expenses related to customer service and sales; a $14.4 million decrease in expenses related to lower sales and fewer subscribers at SouthernLINC Wireless; and a $13.9 million decrease in expenses related to lower litigation costs resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009, as well as the fourth quarter 2008 settlement with the IRS regarding several leveraged lease investments. See Note (B) to the Condensed Financial Statements under “Mirant Matters – MC Asset Recovery Litigation” and “Income Tax Matters – Leveraged Leases” herein for additional information. Partially offsetting the year-to-date 2009 decrease was a $15.8 million increase in administration and general expenses largely related to the $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition program at Georgia Power under which 579 employees elected to resign their positions effective March 31, 2009. Through the third quarter 2009, approximately two-thirds of the $29.4 million charge was offset by lower salary and employee benefits costs, and the remaining one-third will be offset during the fourth quarter 2009. This charge is not expected to have a material impact on Southern Company financial statements for the year ending December 31, 2009.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MC Asset Recovery Litigation Settlement
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
    $202.0   N/M
 
N/M – Not Meaningful
In the first quarter 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202.0 million. See Note (B) to the Condensed Financial Statements under “Mirant Matters – MC Asset Recovery Litigation” herein for additional information.
Depreciation and Amortization
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(34.9)   (9.5)   $29.6   2.8
 
In the third quarter 2009, depreciation and amortization was $332.1 million compared to $367.0 million for the corresponding period in 2008. The decrease was primarily the result of $54.0 million of amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC, partially offset by an increase in plant in service related to environmental, transmission, and distribution projects at Georgia Power.
For year-to-date 2009, depreciation and amortization was $1.10 billion compared to $1.07 billion for the corresponding period in 2008. The increase was primarily the result of an increase in plant in service related to environmental, transmission, and distribution projects at Alabama Power and Georgia Power and the completion of Southern Power’s Plant Franklin Unit 3 in June 2008, as well as an increase in depreciation rates at Southern Power. The increase was partially offset by $54.0 million of amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC.
See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Retail Rate Matters” herein for additional information regarding the Georgia PSC order.
Taxes Other Than Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.4)   (1.1)   $18.3   3.0
 
In the third quarter 2009, taxes other than income taxes were $212.9 million compared to $215.3 million for the corresponding period in 2008. The decrease when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, taxes other than income taxes were $620.9 million compared to $602.6 million for the corresponding period in 2008. The increase was primarily the result of increases in state and municipal public utility license tax bases at Alabama Power and increases in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from retail energy sales.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$15.6   43.7   $29.6   26.5
 
In the third quarter 2009, AFUDC was $51.1 million compared to $35.5 million for the corresponding period in 2008.
For year-to-date 2009, AFUDC was $141.2 million compared to $111.6 million for the corresponding period in 2008.
The third quarter and year-to-date 2009 increases were primarily the result of additional investments in environmental projects at Alabama Power and Gulf Power, as well as additional investments in transmission and distribution projects at Alabama Power.
Leveraged Lease Income (Losses)
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$0.3   3.7   $78.3   146.1
 
In the third quarter 2009, leveraged lease income (losses) was $6.6 million compared to $6.3 million for the corresponding period in 2008. The increase when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, leveraged lease income (losses) was $24.7 million compared to $(53.6) million for the corresponding period in 2008. Southern Company has several leveraged lease investments in international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The year-to-date 2009 increase was primarily the result of the 2008 application of certain accounting standards related to leveraged leases, including a second quarter 2008 after tax charge of $51.2 million. See Note (B) to the Condensed Financial Statements under “Income Tax Matters – Leveraged Leases” herein for additional information.
Gain on Disposition of Lease Termination
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
    $26.3   N/M
 
N/M — Not Meaningful
In the second quarter 2009, Southern Company terminated two international leveraged lease investments early, which resulted in a gain of $26.3 million.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Loss on Extinguishment of Debt
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
    $17.2   N/M
 
N/M — Not Meaningful
In the second quarter 2009, Southern Company terminated two international leveraged lease investments early. The proceeds from the terminations were required to be used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions which resulted in a loss of $17.2 million.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$7.2   3.3   $19.8   3.0
 
In the third quarter 2009, interest expense, net of amounts capitalized was $226.3 million compared to $219.1 million for the corresponding period in 2008. The increase when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, interest expense, net of amounts capitalized was $684.9 million compared to $665.1 million for the corresponding period in 2008. The increase in expense was primarily the result of an $83.0 million increase associated with $1.30 billion in additional debt outstanding at September 30, 2009 compared to September 30, 2008. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Southern Company in Item 7 of the Form 10-K and herein for additional information. Partially offsetting this increase was a $44.3 million decrease related to lower average interest rates on existing variable rate debt, including the impact of hedges, a $13.4 million decrease related to other interest charges, and $5.5 million of additional capitalized interest when compared to the corresponding period in 2008.
Other Income (Expense), Net
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$0.4   3.6   $(12.6)   (87.4)
 
In the third quarter 2009, other income (expense), net was $(10.4) million compared to $(10.8) million for the corresponding period in 2008. The decrease in expense when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, other income (expense), net was $(27.0) million compared to $(14.4) million for the corresponding period in 2008. The increase in expense was primarily the result of the first quarter 2008 recognition of a $6.4 million fee received for participating in an asset auction and a $6.0 million gain on the sale of an undeveloped tract of land to the Orlando Utilities Commission.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.4   0.3   $(8.8)   (1.0)
 
In the third quarter 2009, income taxes were $435.9 million compared to $434.5 million for the corresponding period in 2008. The increase was primarily the result of higher pre-tax earnings, largely offset by the third quarter 2009 increase in AFUDC, which is not taxable. See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of AFUDC on the effective tax rate.
For year-to-date 2009, income taxes were $828.8 million compared to $837.6 million for the corresponding period in 2008. The decrease was primarily the result of lower pre-tax earnings, lower tax expense associated with the early termination of one of the international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Gain on Disposition of Lease Termination” and “Loss on Extinguishment of Debt,” and the year-to-date increase in AFUDC, which is not taxable. Partially offsetting this decrease was the $202.0 million charge resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009, which has not been deducted for tax purposes. See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of the early lease termination, AFUDC, and the MC Asset Recovery litigation settlement on the effective tax rate.
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 recovery of prudently incurred costs during a time of increasing costs and the profitability of the competitive wholesale supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Recessionary conditions have negatively impacted sales for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. The current economic recession is expected to continue to have a negative impact on energy sales, particularly to industrial and commercial customers. The timing and extent of the economic recovery will 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. 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 to 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 September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters 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 September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and 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 the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Southern Company’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges 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 Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Global Climate Issues
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Global Climate Issues” of Southern Company in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.
In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Company’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
FERC and State PSC Matters
Market-Based Rate Authority
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $697 million at September 30, 2009. During the third quarter 2009, Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2009, have a total over recovered fuel balance of $66 million. The total under recovered fuel costs included in the balance sheets of the traditional operating companies at December 31, 2008 was $1.2 billion. Operating revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income but will affect cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balance. 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 “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Gulf Power Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.
On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009 and, on August 27, 2009, the Georgia PSC approved an additional delay in the filing date to no later than December 15, 2009 (with new rates to be effective April 1, 2010).
Retail Rate Matters
Under the 2007 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. In connection with the 2007 Retail Rate Plan, the Georgia PSC ordered that Georgia Power file its next general base rate case by July 1, 2010; however, the 2007 Retail Rate Plan provided that Georgia Power may file for a general base rate increase in the event its projected retail ROE falls below 10.25%.
The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations.
On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, if Georgia Power does not file for a retail base rate increase in 2009, Georgia Power will be entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009. Through September 30, 2009, Georgia Power has amortized $54 million of the regulatory liability. In addition, Georgia Power will be entitled to amortize up to two-thirds of the regulatory liability ($216 million) in 2010. In the event Georgia Power files for a retail base rate increase prior to July 1, 2010, then the amortization of the regulatory liability in 2010 would be reduced by one-sixth for each month that such rate case is filed prior to July 1, 2010.

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Furthermore, the amortization of the regulatory liability is limited to only the amount that would allow Georgia Power to earn a retail ROE not more than 9.75% in 2009 and 10.15% in 2010. In addition, Georgia Power may not file for a base rate increase prior to July 1, 2010 unless economic conditions beyond its control continue to reduce Georgia Power’s projected retail ROE and in no event unless Georgia Power’s projected retail ROE for 2009 or 2010 is less than 9.25% after taking into consideration amortization of the regulatory liability.
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Southern Company. Southern Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $225 million and $275 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Southern Company continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.
Construction Projects
Integrated Coal Gasification Combined Cycle
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction Projects - Integrated Coal Gasification Combined Cycle” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.
On May 11, 2009, Mississippi Power received notification from the IRS formally certifying the Internal Revenue Code Section 48A tax credits of $133 million to Mississippi Power. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014.
On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. Mississippi Power expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law.
On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of September 30, 2009, Mississippi Power had spent a total of $64.5 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the nine months ended September 30, 2009 totaled $22.2 million as compared to $18.1 million for the nine months ended September 30, 2008. Of the total $64.5 million, $59.8 million was deferred in other regulatory assets, $3.9 million was related to land purchases capitalized, and $0.8 million was previously expensed.

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Several motions were filed by intervenors, most of which were procedural in nature and sought to stay or delay the timely and orderly administration of the docket. In addition to these procedural motions, a motion was filed by the Attorney General for the State of Mississippi which questioned whether the Mississippi PSC had authority to approve the gasification portion of the Kemper IGCC. On June 5, 2009, all of these motions were denied by the Mississippi PSC.
On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. During Phase I, the Mississippi PSC will determine if a need exists for new generating resources. Hearings for Phase I were held in October 2009, and a decision is expected in November 2009. If it is determined a need exists in Phase I, the appropriate resource to fill the need as well as the cost recovery of that resource through application of the State of Mississippi’s Baseload Act of 2008 will be determined during Phase II. Hearings regarding Phase II issues are scheduled for February 2010 with a decision by May 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Mississippi Base Load Construction Legislation” of Southern Company in Item 7 of the Form 10-K for information regarding the Baseload Act of 2008.
On September 15, 2009, South Mississippi Electric Power Association (SMEPA) signed a non-binding letter of intent to explore the acquisition of an interest in the Kemper IGCC. Mississippi Power and SMEPA are evaluating a combination of a joint ownership arrangement and a PPA which would provide SMEPA with up to 20% of the capacity and associated energy output from the Kemper IGCC.
The ultimate outcome of these matters cannot now be determined.
Nuclear
See Note (B) to the Condensed Financial Statements under “Construction Projects – Nuclear” herein for information regarding the potential expansion of Plant Vogtle.
On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.5 billion.
On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.
On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. Georgia Power believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions. The ultimate outcome of this matter cannot be determined at this time.
On August 26, 2009, the NRC issued the Early Site Permit and Limited Work Authorization for Plant Vogtle Units 3 and 4. Excavation for the new units is in progress.

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On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4. The ultimate outcome of this matter cannot be determined at this time.
On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any change to the estimated construction cost as certified by the Georgia PSC in March 2009. The Georgia PSC will conduct hearings between November 2009 and January 2010 in review of this report and is scheduled to render its decision on February 18, 2010. The ultimate outcome of this matter cannot be determined at this time.
There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot now be determined.
Nuclear Relicensing
The NRC operating licenses for Plant Vogtle Units 1 and 2 were scheduled to expire in January 2027 and February 2029, respectively. In June 2007, Georgia Power filed an application with the NRC to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. On June 3, 2009, the NRC approved the extension of the licenses as requested.
Other Matters
Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. Southern Company’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 United States. In particular, personal injury 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 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 liabilities, if any, arising from such current proceedings would have a material adverse 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements 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, and Unbilled Revenues.
New Accounting Standards
Variable Interest Entities
In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Southern Company is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Southern Company and its subsidiaries have maintained adequate access to capital without drawing on any committed bank credit arrangements used to support commercial paper programs and variable rate pollution control revenue bonds. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Southern Company and its subsidiaries have been and expect to continue to be subject to higher costs as existing facilities are replaced or renewed. Total committed credit fees for Southern Company and its subsidiaries currently average less than 1/2 of 1% per year. Southern Company’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Southern Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.
Southern Company’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

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For the first nine months of 2009, net cash provided from operating activities totaled $2.4 billion, a decrease of $276 million from the corresponding period in 2008. Significant changes in operating cash flow for the first nine months of 2009 as compared to the corresponding period in 2008 include a reduction to net income as previously discussed and increased levels of coal inventory of $249 million. These uses of funds were partially offset by increased cash inflows as a result of higher fuel cost recovery rates included in customer billings. Net cash used for investing activities totaled $2.9 billion for the first nine months of 2009 as compared to $3.0 billion for the corresponding period in 2008. While the cash outflows in each of these periods were primarily related to property additions to utility plant, the decrease in the current period as compared to the corresponding period in 2008 was primarily due to approximately $340 million in cash received from the early termination of two leveraged lease investments. For the first nine months of 2009, net cash provided from financing activities totaled $687 million as compared to $949 million for the corresponding period in 2008. The funds available from financing activities were primarily attributable to cash inflows from short-term borrowings, the issuance of new long-term debt, and common stock issuances, partially offset by cash outflows for repayments of long-term debt and dividend payments.
Significant balance sheet changes for the first nine months of 2009 include an increase of $2.3 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 an increase in long-term debt, excluding amounts due within one year, of $1.2 billion used primarily for construction expenditures and general corporate purposes and $1.1 billion of additional equity.
The market price of Southern Company’s common stock at September 30, 2009 was $31.67 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $17.95 per share, representing a market-to-book ratio of 176%, compared to $37.00, $17.08, and 217%, respectively, at the end of 2008. The dividend for the third quarter 2009 was $0.4375 per share compared to $0.42 per share in the third quarter 2008.
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 its construction programs 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 $412 million will be required through September 30, 2010 to fund maturities of long-term debt. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; 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 2009, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes

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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 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.
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), to meet liquidity needs. At September 30, 2009, Southern Company and its subsidiaries had approximately $607 million of cash and cash equivalents and approximately $4.7 billion of unused credit arrangements with banks, of which $99 million expire in 2009, $1.4 billion expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $84 million of the credit facilities expiring in 2009 and 2010 allow for the execution of term loans for an additional two-year period, and $512 million contain provisions allowing one-year term loans. At September 30, 2009, approximately $1.6 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and such credit facilities also serve as liquidity support for the commercial paper programs. 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, 2009, the Southern Company system had outstanding commercial paper of $1.1 billion. 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 related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel.
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, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $422 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.1 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.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On September 2, 2009, Moody’s affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A3/P-1, respectively, and revised the rating outlook for Southern Company to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A-/A-1, respectively, and maintained a stable rating outlook. On September 4, 2009, Fitch affirmed Southern Company’s long-term and commercial paper credit ratings of A/F1, respectively, and maintained its stable rating outlook.
Market Price Risk
Southern Company’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Company 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, the traditional operating companies continue to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern 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, during 2009, Southern Power is exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, Southern Company’s subsidiaries may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, the traditional operating companies have no material change in market risk exposure when compared with the December 31, 2008 reporting period.
The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:
                 
    Third Quarter   Year-to-Date
    2009   2009
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (302 )   $ (285 )
Contracts realized or settled
    131       318  
Current period changes(a)
    8       (196 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (163 )   $ (163 )
 
(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were an increase of $139 million and $122 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Southern Company had a net hedge volume of 154 million mmBtu (includes location basis of 2 million mmBtu) with a weighted average contract cost approximately $1.09 per mmBtu above market prices, compared to 173 million mmBtu (includes location basis of 2 million mmBtu) at June 30, 2009 with a weighted average contract cost approximately $1.78 per mmBtu above market prices and compared to 149 million mmBtu at December 31, 2008 with a weighted average contract cost

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the traditional operating companies’ fuel cost recovery clauses.
At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
                 
Asset (Liability) Derivatives   September 30, 2009   December 31, 2008
    (in millions)
Regulatory hedges
  $ (167 )   $ (288 )
Cash flow hedges
    (1 )     (1 )
Not designated
    5       4  
 
Total fair value
  $ (163 )   $ (285 )
 
Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives designated as cash flow hedges are mainly used 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 recognized in the statements of income for the three months and nine months ended September 30, 2009 for energy-related derivative contracts that are not hedges were $2 million and $1 million, respectively. The total net unrealized gain recognized in the statements of income for the three months ended September 30, 2008 was $7 million and was not material for the nine months ended September 30, 2008. See Note (E) to the Condensed Financial Statements herein for further details of these gains (losses).
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:
                                 
    September 30, 2009
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (163 )     (123 )     (40 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (163 )   $ (123 )   $ (40 )   $  
 
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Company in Item 7 and Notes 1 and 6 to the financial statements of Southern Company under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In the first nine months of 2009, Southern Company issued $350 million of Series 2009A 4.15% Senior Notes due May 15, 2014, and its subsidiaries issued $1.3 billion of senior notes and incurred obligations of $600 million related to the issuance of pollution control revenue bonds. Southern Company also issued 17 million shares of common stock for $501 million through the Southern Investment Plan, Dividend Reinvestment Plan, and employee and director stock plans. In addition, Southern Company issued 6 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $167 million, net of $1.7 million in fees and commissions. The proceeds were primarily used to fund ongoing construction projects, to repay short-term and long-term indebtedness, and for general corporate purposes.
In July 2009, Gulf Power entered into a forward starting interest rate swap to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swap is $50 million, and the swap has been designated as a cash flow hedge.
In July 2009, Southern Company used a portion of the cash received from the early termination of two leveraged lease investments to extinguish $252.7 million of debt which included all debt related to leveraged lease investments and to pay make-whole redemption premiums of $17.2 million associated with such debt.
In August 2009, Georgia Power redeemed its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.
In August 2009, Georgia Power’s $125 million Series V 4.10% Senior Notes due August 15, 2009 matured.
In August 2009, Alabama Power’s $250 million Series BB Floating Rate Senior Notes due August 25, 2009 matured.
Subsequent to September 30, 2009, Southern Company issued $300 million of Series 2009B Floating Rate Senior Notes due October 21, 2011. The proceeds were used to repay short-term indebtedness and other general corporate purposes.
Subsequent to September 30, 2009, Georgia Power and Gulf Power entered into forward starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amounts of the swaps totaled $200 million and $50 million, respectively, and the swaps have been designated as cash flow hedges.
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 Notes 1 and 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Financial Instruments” in Item 8 of the Form 10-K. Also, see Note (E) 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 conducted an evaluation under the supervision and with the participation of Southern 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 this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.
     (b) Changes in internal controls over financial reporting.
There have been no changes in Southern Company’s internal control over financial reporting (as such term is defined in Sections 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the third quarter 2009 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting.
Item 4T. Controls and Procedures.
     (a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this quarterly report, 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 over financial reporting.
There have been no changes in 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 Sections 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the third quarter 2009 that have materially affected or are reasonably likely to materially affect 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,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 1,342,665     $ 1,559,034     $ 3,520,408     $ 3,741,074  
Wholesale revenues, non-affiliates
    170,573       196,381       483,180       536,392  
Wholesale revenues, affiliates
    34,042       60,583       170,887       240,696  
Other revenues
    44,876       49,084       123,963       153,412  
 
                       
Total operating revenues
    1,592,156       1,865,082       4,298,438       4,671,574  
 
                       
Operating Expenses:
                               
Fuel
    506,376       651,673       1,437,095       1,628,170  
Purchased power, non-affiliates
    42,915       104,238       84,582       153,907  
Purchased power, affiliates
    73,966       121,651       172,096       286,147  
Other operations and maintenance
    272,118       300,967       827,275       917,060  
Depreciation and amortization
    136,784       132,410       406,687       387,677  
Taxes other than income taxes
    77,353       76,200       239,673       227,585  
 
                       
Total operating expenses
    1,109,512       1,387,139       3,167,408       3,600,546  
 
                       
Operating Income
    482,644       477,943       1,131,030       1,071,028  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    21,053       11,730       56,931       32,269  
Interest income
    4,419       4,794       12,689       13,694  
Interest expense, net of amounts capitalized
    (75,817 )     (71,165 )     (224,792 )     (209,787 )
Other income (expense), net
    (6,714 )     (5,732 )     (17,577 )     (19,661 )
 
                       
Total other income and (expense)
    (57,059 )     (60,373 )     (172,749 )     (183,485 )
 
                       
Earnings Before Income Taxes
    425,585       417,570       958,281       887,543  
Income taxes
    154,050       156,109       344,416       323,335  
 
                       
Net Income
    271,535       261,461       613,865       564,208  
Dividends on Preferred and Preference Stock
    9,866       9,866       29,598       29,598  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 261,669     $ 251,595     $ 584,267     $ 534,610  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 261,669     $ 251,595     $ 584,267     $ 534,610  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(187), $50, $(1,773), and $(989), respectively
    (307 )     83       (2,916 )     (1,627 )
Reclassification adjustment for amounts included in net income, net of tax of $1,217, $82, $3,456, and $710, respectively
    2,002       135       5,685       1,168  
 
                       
Total other comprehensive income (loss)
    1,695       218       2,769       (459 )
 
                       
Comprehensive Income
  $ 263,364     $ 251,813     $ 587,036     $ 534,151  
 
                       
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,  
    2009     2008  
    (in thousands)  
Operating Activities:
               
Net income
  $ 613,865     $ 564,208  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    474,250       451,182  
Deferred income taxes and investment tax credits, net
    (32,333 )     109,459  
Allowance for equity funds used during construction
    (56,931 )     (32,269 )
Pension, postretirement, and other employee benefits
    (2,955 )     (133 )
Stock option expense
    3,475       2,822  
Tax benefit of stock options
    79       641  
Other, net
    25,223       22,717  
Changes in certain current assets and liabilities —
               
-Receivables
    232,890       (92,774 )
-Fossil fuel stock
    (20,609 )     (61,753 )
-Materials and supplies
    (22,783 )     (19,915 )
-Other current assets
    (43,436 )     (33,840 )
-Accounts payable
    (197,357 )     (62,186 )
-Accrued taxes
    168,493       92,749  
-Accrued compensation
    (46,583 )     (27,786 )
-Other current liabilities
    70,111       22,248  
 
           
Net cash provided from operating activities
    1,165,399       935,370  
 
           
Investing Activities:
               
Property additions
    (896,913 )     (1,024,668 )
Investment in restricted cash from pollution control revenue bonds
    (340 )     (5,454 )
Distribution of restricted cash from pollution control revenue bonds
    39,866       24,585  
Nuclear decommissioning trust fund purchases
    (177,639 )     (218,606 )
Nuclear decommissioning trust fund sales
    177,639       218,606  
Cost of removal, net of salvage
    (21,419 )     (33,579 )
Other investing activities
    10,342       (26,839 )
 
           
Net cash used for investing activities
    (868,464 )     (1,065,955 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (24,995 )     94,891  
Proceeds —
               
Common stock issued to parent
    135,000       225,000  
Capital contributions from parent company
    17,177       15,095  
Gross excess tax benefit of stock options
    173       1,226  
Pollution control revenue bonds
    53,000       131,100  
Senior notes issuances
    500,000       600,000  
Redemptions —
               
Preferred stock
          (125,000 )
Pollution control revenue bonds
          (11,100 )
Senior notes
    (250,000 )     (250,000 )
Payment of preferred and preference stock dividends
    (29,602 )     (31,024 )
Payment of common stock dividends
    (392,100 )     (368,475 )
Other financing activities
    (2,647 )     (6,467 )
 
           
Net cash provided from financing activities
    6,006       275,246  
 
           
Net Change in Cash and Cash Equivalents
    302,941       144,661  
Cash and Cash Equivalents at Beginning of Period
    28,181       73,616  
 
           
Cash and Cash Equivalents at End of Period
  $ 331,122     $ 218,277  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $23,813 and $14,649 capitalized for 2009 and 2008, respectively)
  $ 190,014     $ 183,218  
Income taxes (net of refunds)
  $ 274,486     $ 197,907  
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   2009     2008  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 331,122     $ 28,181  
Restricted cash and cash equivalents
    40,554       80,079  
Receivables —
               
Customer accounts receivable
    422,926       350,410  
Unbilled revenues
    122,056       98,921  
Under recovered regulatory clause revenues
    31,949       153,899  
Other accounts and notes receivable
    30,210       44,645  
Affiliated companies
    58,844       70,612  
Accumulated provision for uncollectible accounts
    (9,891 )     (8,882 )
Fossil fuel stock, at average cost
    337,873       322,089  
Materials and supplies, at average cost
    326,964       305,880  
Vacation pay
    52,949       52,577  
Prepaid expenses
    130,487       88,219  
Other regulatory assets, current
    42,121       74,825  
Other current assets
    14,726       12,915  
 
           
Total current assets
    1,932,890       1,674,370  
 
           
Property, Plant, and Equipment:
               
In service
    18,078,745       17,635,129  
Less accumulated provision for depreciation
    6,516,289       6,259,720  
 
           
Plant in service, net of depreciation
    11,562,456       11,375,409  
Nuclear fuel, at amortized cost
    231,110       231,862  
Construction work in progress
    1,474,821       1,092,516  
 
           
Total property, plant, and equipment
    13,268,387       12,699,787  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    58,469       50,912  
Nuclear decommissioning trusts, at fair value
    465,208       403,966  
Miscellaneous property and investments
    68,488       62,782  
 
           
Total other property and investments
    592,165       517,660  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    390,240       362,596  
Prepaid pension costs
    197,172       166,334  
Deferred under recovered regulatory clause revenues
          180,874  
Other regulatory assets, deferred
    690,530       732,367  
Other deferred charges and assets
    198,898       202,018  
 
           
Total deferred charges and other assets
    1,476,840       1,644,189  
 
           
Total Assets
  $ 17,270,282     $ 16,536,006  
 
           
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   2009     2008  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $     $ 250,079  
Notes payable
          24,995  
Accounts payable —
               
Affiliated
    166,865       178,708  
Other
    210,348       358,176  
Customer deposits
    85,242       77,205  
Accrued taxes —
               
Accrued income taxes
    95,262       18,299  
Other accrued taxes
    96,857       30,372  
Accrued interest
    69,985       56,375  
Accrued vacation pay
    44,217       44,217  
Accrued compensation
    54,687       91,856  
Liabilities from risk management activities
    48,780       83,873  
Other regulatory liabilities, current
    56,616       3,462  
Other current liabilities
    40,140       50,315  
 
           
Total current liabilities
    968,999       1,267,932  
 
           
Long-term Debt
    6,156,960       5,604,791  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,281,537       2,243,117  
Deferred credits related to income taxes
    88,961       90,083  
Accumulated deferred investment tax credits
    166,683       172,638  
Employee benefit obligations
    417,991       396,923  
Asset retirement obligations
    483,465       461,284  
Other cost of removal obligations
    667,655       634,792  
Other regulatory liabilities, deferred
    112,111       79,151  
Other deferred credits and liabilities
    35,654       45,857  
 
           
Total deferred credits and other liabilities
    4,254,057       4,123,845  
 
           
Total Liabilities
    11,380,016       10,996,568  
 
           
Redeemable Preferred Stock
    341,716       341,716  
 
           
Preference Stock
    343,412       343,412  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $40 per share —
               
Authorized - 40,000,000 shares
               
Outstanding - September 30, 2009: 28,850,000 shares
               
- December 31, 2008: 25,475,000 shares
    1,154,000       1,019,000  
Paid-in capital
    2,112,359       2,091,462  
Retained earnings
    1,945,959       1,753,797  
Accumulated other comprehensive loss
    (7,180 )     (9,949 )
 
           
Total common stockholder’s equity
    5,205,138       4,854,310  
 
           
Total Liabilities and Stockholder’s Equity
  $ 17,270,282     $ 16,536,006  
 
           
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 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail 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 energy sales in the midst of the current economic downturn, 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, capital expenditures, and restoration following major storms. Appropriately balancing the need to recover these increasing costs 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 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$10.1   4.0   $49.7   9.3
 
Alabama Power’s financial performance remained stable in the third quarter 2009 despite the continued challenges of a recessionary economy. Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2009 was $261.7 million compared to $251.6 million for the corresponding period in 2008. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures effective in January 2009, a decrease in other operations and maintenance expense, and an increase in allowance for equity funds used during construction (AFUDC). The increase was partially offset by an overall decline in base revenues attributable to a decline in KWH sales, resulting from a recessionary economy and unfavorable weather conditions.
Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2009 was $584.3 million compared to $534.6 million for the corresponding period in 2008. The increase was primarily due to a decrease in other operations and maintenance expense, an increase in AFUDC, and an overall increase in base revenues resulting from a corrective rate package that began in January 2009, offset by a decline in KWH sales resulting from a recessionary economy and unfavorable weather conditions.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(216.4)   (13.9)   $(220.7)   (5.9)
 
In the third quarter 2009, retail revenues were $1.34 billion compared to $1.56 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $3.52 billion compared to $3.74 billion for the corresponding period in 2008.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2009   2009
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 1,559.0             $ 3,741.1          
Estimated change in —
                               
Rates and pricing
    36.7       2.4       127.1       3.4  
Sales growth (decline)
    (30.6 )     (2.0 )     (103.5 )     (2.8 )
Weather
    (17.1 )     (1.1 )     (14.4 )     (0.4 )
Fuel and other cost recovery
    (205.3 )     (13.2 )     (229.9 )     (6.1 )
 
Retail – current year
  $ 1,342.7       (13.9 )%   $ 3,520.4       (5.9 )%
 
Revenues associated with changes in rates and pricing increased in the third quarter 2009 and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to the corrective rate package increase effective January 2009, which mainly provided for adjustments associated with customer charges to certain existing rate structures. 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.
Revenues attributable to changes in sales declined in the third quarter 2009 when compared to the corresponding period in 2008 due to a recessionary economy. Industrial KWH energy sales decreased 11.9% due to a decline in demand across all industrial segments, most significantly in the chemical, forest products, and primary metal sectors. The weather-adjusted residential KWH energy sales decline was not material. Weather-adjusted commercial KWH energy sales decreased 3.2% due to a decline in customer demand resulting from a recessionary economy.
For year-to-date 2009, revenues attributable to changes in sales declined due to a recessionary economy when compared to the corresponding period in 2008. Industrial KWH energy sales decreased 19.2% due to a decline in demand across all industrial segments, most significantly in the chemical, forest products, and primary metal sectors. Weather-adjusted residential and commercial KWH energy sales decreased 1.5% and 2.3%, respectively, driven by a decline in customer demand.
Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2009 due to unfavorable weather conditions compared to the corresponding period in 2008.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to decreases in fuel costs. 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 natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(25.8)   (13.1)   $(53.2)   (9.9)
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Alabama Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.
In the third quarter 2009, wholesale revenues from non-affiliates were $170.6 million compared to $196.4 million for the corresponding period in 2008. The decrease was due to a 9.1% reduction in the price of energy and a 4.4% decrease in KWH sales primarily caused by the recessionary economy.
For year-to-date 2009, wholesale revenues from non-affiliates were $483.2 million compared to $536.4 million for the corresponding period in 2008. The decrease was due to a 6.6% reduction in the price of energy and a 3.6% decrease in KWH sales primarily caused by the recessionary economy.
Wholesale Revenues – Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(26.6)   (43.8)   $(69.8)   (29.0)
 
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 2009, wholesale revenues from affiliates were $34.0 million compared to $60.6 million for the corresponding period in 2008. The decrease was due to a 60.4% decrease in fuel prices, partially offset by a 41.8% increase in KWH sales.
For year-to-date 2009, wholesale revenues from affiliates were $170.9 million compared to $240.7 million for the corresponding period in 2008. The decrease was due to a 41.0% decrease in fuel prices, partially offset by a 20.4% increase in KWH sales.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(4.2)   (8.6)   $(29.4)   (19.2)
 
In the third quarter 2009, the decrease in other revenues when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, other revenues were $124.0 million compared to $153.4 million for the corresponding period in 2008. The decrease was primarily due to a $39.6 million decrease in revenues from gas-fueled co-generation steam facilities resulting from lower gas prices and a decline in sales volume, partially offset by a $7.3 million increase in customer charges related to late fees.
Co-generation steam fuel revenues do not have a significant impact on earnings since they are generally offset by fuel expenses.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2009   Year-to-Date 2009
    vs.   vs.
    Third Quarter 2008   Year-to-Date 2008
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ (145.3 )     (22.3 )   $ (191.1 )     (11.7 )
Purchased power – non-affiliates
    (61.3 )     (58.8 )     (69.3 )     (45.0 )
Purchased power – affiliates
    (47.7 )     (39.2 )     (114.0 )     (39.9 )
                         
Total fuel and purchased power expenses
  $ (254.3 )           $ (374.4 )        
                         
* 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 2009, total fuel and purchased power expenses were $623.3 million compared to $877.6 million for the corresponding period in 2008. The decrease was primarily due to a $145.7 million decrease in the cost of energy primarily resulting from a decrease in the average cost of purchased power and natural gas and $108.6 million decrease related to total KWHs generated and purchased.
For year-to-date 2009, total fuel and purchased power expenses were $1.69 billion compared to $2.07 billion for the corresponding period in 2008. The decrease was primarily due to a $262.1 million decrease related to total KWHs generated and purchased and a $112.3 million decrease in the cost of energy primarily resulting from a decrease in the average cost of purchased power and natural gas.
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 – “FERC and Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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   2009   2008   Change   2009   2008   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    2.80       3.29       (14.9 )     2.83       2.88       (1.7 )
Purchased power
    6.45       9.21       (30.0 )     6.23       7.95       (21.6 )
 
In the third quarter 2009, fuel expense was $506.4 million compared to $651.7 million for the corresponding period in 2008. The decrease was primarily due to a 40.8% and 8.2% decrease in the average cost of KWHs generated by natural gas and coal, respectively. Lower natural gas prices and an increase in hydro generation resulted in a decrease in the KWHs generated by coal and an increase in the KWHs generated by natural gas.
For year-to-date 2009, fuel expense was $1.44 billion compared to $1.63 billion for the corresponding period in 2008. The decrease was primarily related a 39.3% decrease in the average cost of KWHs generated by natural gas and a 10.1% increase the average cost of KWHs generated by coal. Lower natural gas prices and an increase in hydro generation resulted in a decrease in the KWHs generated by coal and an increase in the KWHs generated by natural gas.
Non-Affiliates
In the third quarter 2009, purchased power from non-affiliates was $42.9 million compared to $104.2 million for the corresponding period in 2008. The decrease was primarily related to a 58.0% volume decrease in the KWHs purchased primarily caused by reduced demand due to the recessionary economy.
For year-to-date 2009, purchased power from non-affiliates was $84.6 million compared to $153.9 million for the corresponding period in 2008. The decrease was related to a 26.7% decrease in KWHs purchased primarily caused by reduced demand due to the recessionary economy and a 25.0% decrease in price.
Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than 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.
Affiliates
In the third quarter 2009, purchased power from affiliates was $74.0 million compared to $121.7 million for the corresponding period in 2008. The decrease was related to a 22.0% decrease in the amount of energy purchased and a 22.0% decrease in price.
For year-to-date 2009, purchased power from affiliates was $172.1 million compared to $286.1 million for the corresponding period in 2008. The decrease was related to a 28.6% decrease in the amount of energy purchased and a 15.8% decrease in price.
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, as approved by the FERC.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(28.9)   (9.6)   $(89.8)   (9.8)
 
In the third quarter 2009, other operations and maintenance expenses were $272.1 million compared to $301.0 million for the corresponding period in 2008. The decrease was a result of a $7.0 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing costs and labor, a $6.8 million decrease in nuclear expense related to a reduction in contract labor and material expenses, a $4.6 million decrease in steam power expense related to fewer scheduled outages, a $3.9 million decrease in administrative and general expenses related to a reduction in the injuries and damages reserve, partially offset by an increase in affiliated service company expenses, and a $2.1 million decrease in customer service expenses.
For year-to-date 2009, other operations and maintenance expenses were $827.3 million compared to $917.1 million for the corresponding period in 2008. The decrease was a result of a $46.4 million decrease in steam power expense related to reduction in contract labor and fewer scheduled outages, a $22.0 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing and labor, and an $11.0 million decrease in administrative and general expenses related to reductions in the injuries and damages reserve, and post retirement medical expense, partially offset by an increase in pension expenses.
Depreciation and Amortization
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$4.4   3.3   $19.0   5.0
 
In the third quarter 2009, the increase in depreciation and amortization when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, depreciation and amortization was $406.7 million compared to $387.7 million for the corresponding period in 2008. The increase was the result of an increase in property, plant, and equipment primarily related to environmental mandates and transmission and distribution projects.
On June 25, 2009, Alabama Power submitted an offer of settlement and stipulation to the FERC relating to the 2008 depreciation study that was filed in October 2008. The settlement offer withdraws the requests for authorization to use updated depreciation rates. In lieu of the new rates, Alabama Power will use those depreciation rates employed prior and up to January 1, 2009 that were previously approved by the FERC. On September 30, 2009, the FERC issued an order approving the settlement offer.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Depreciation and Amortization” of Alabama Power in Item 7 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
Taxes Other Than Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.2   1.5   $12.1   5.3
 
In the third quarter 2009, the increase in taxes other than income taxes when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, taxes other than income taxes were $239.7 million compared to $227.6 million for the corresponding period in 2008. The increase was primarily due to increases in state and municipal public utility license tax bases.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$9.4   79.5   $24.6   76.4
 
In the third quarter 2009, AFUDC was $21.1 million compared to $11.7 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $56.9 million compared to $32.3 million for the corresponding period in 2008. These increases were primarily due to increases in the amount of construction work in progress at generating facilities related to environmental mandates.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$4.7   6.5   $15.0   7.2
 
In the third quarter 2009, the increase in interest expense, net of amounts capitalized when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, interest expense, net of amounts capitalized was $224.8 million compared to $209.8 million for the corresponding period in 2008. The increase was primarily due to the issuance of additional long-term debt, partially offset by additional capitalized interest. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.
Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.0)   (1.3)   $21.1   6.5
 
In the third quarter 2009, income taxes were $154.1 million compared to $156.1 million for the corresponding period in 2008. The decrease was primarily due to the increase in non-taxable AFUDC and the manufacturer’s deduction, partially offset by higher pre-tax income and actualization of the 2008 income tax return.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2009, income taxes were $344.4 million compared to $323.3 million for the corresponding period in 2008. The increase was primarily due to higher pre-tax income, partially offset by the increase in non-taxable AFUDC.
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 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. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery will 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.
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. 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.
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 to 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 September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters 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 September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and 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 the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Alabama Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges 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 the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.
Global Climate Issues
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Global Climate Issues” of Alabama Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.
In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Alabama Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
FERC and Alabama PSC Matters
Market-Based Rate Authority
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail 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 over recovered fuel costs as of September 30, 2009 totaled $54.9 million as compared to under recovered fuel costs of $305.8 million at December 31, 2008. These over recovered fuel costs at September 30, 2009 are included in other regulatory liabilities, current on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 return of the over recovered fuel costs.
On June 2, 2009, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 3.983 cents per KWH to 3.733 cents per KWH for billings beginning June 9, 2009 through October 8, 2010, which will have no significant effect on Alabama Power’s revenues or net income, but will decrease annual cash flow. Thereafter, the Rate ECR factor will be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Alabama Power will be allowed to include a carrying charge associated with under recovered fuel costs in the fuel expense calculation. When the Rate ECR factor results in an over recovered position, Alabama Power will accrue interest on any such over recovered balance at the same rate used to derive the carrying cost.
Natural Disaster Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Cost Recovery” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery. At September 30, 2009, Alabama Power had accumulated a balance of $34.0 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under “Other Regulatory Liabilities.”
Steam Service
On February 5, 2009, the Alabama PSC granted a Certificate of Abandonment of Steam Service in the downtown area of the City of Birmingham. The order allows Alabama Power to discontinue steam service by the earlier of three years from May 14, 2008 or when it has no remaining steam service customers. Currently, Alabama Power has contractual obligations to provide steam service until 2013. Impacts related to the abandonment of steam service are recognized in operating income and are not material to the earnings of Alabama Power.
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Alabama Power. Alabama Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $75 million and $90 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $65 million relates to Alabama Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Alabama Power continues to assess the other financial implications of the ARRA. The ultimate impact 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
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 United States. In particular, personal injury 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 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 liabilities, if any, arising from such current proceedings would have a material adverse effect on Alabama 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
Alabama Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements 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, and Unbilled Revenues.
New Accounting Standards
Variable Interest Entities
In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Alabama Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Alabama Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Alabama Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Alabama Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees currently average less than 1/4 of 1% per year for Alabama Power. Alabama Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Alabama Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.
Alabama Power’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Alabama Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Alabama Power does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time.
Net cash provided from operating activities totaled $1.2 billion for the first nine months of 2009, compared to $935.4 million for the corresponding period in 2008. The $230.0 million increase in cash provided from operating activities was primarily due to an increase in net income, as previously discussed, and a decrease in receivables attributable to collections of under recovered regulatory clauses. Net cash used for investing activities totaled $868.5 million for the first nine months of 2009, compared to $1.1 billion for the corresponding period in 2008. The $197.5 million decrease was primarily due to a decline in gross property additions related to steam generation equipment and purchases of nuclear fuel, partially offset by increased construction of distribution facilities. Net cash provided from financing activities totaled $6.0 million for the first nine months of 2009, compared to $275.2 million for the corresponding period in 2008. The $269.2 million decrease was primarily due to fewer issuances of securities and a decrease of notes payable, partially offset by fewer redemptions of securities in the first nine months of 2009 as compared to the first nine months of 2008. 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 2009 include an increase of $302.9 million in cash and cash equivalents, an increase of $443.6 million in gross plant primarily due to increases in environmental mandates and transmission and distribution projects, and an increase of $382.3 million in construction work in progress. Long-term debt increased $552.2 million.
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 maturities of long-term debt required

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
through September 30, 2010. 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 nuclear plants 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; 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. Recently, 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, 2009 cash and cash equivalents of approximately $331 million, unused committed lines of credit of approximately $1.3 billion, and commercial paper programs. The credit facilities provide liquidity support to Alabama Power’s commercial paper borrowings and $582 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Of the unused credit facilities, $20 million will expire in 2009, $461 million will expire in 2010, $25 million will expire in 2011, and $765 million will expire in 2012. Of the facilities that expire in 2009 and 2010, $372 million allow for one-year term loans. Alabama Power expects to renew its credit facilities, as needed, prior to expiration. 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, 2009, Alabama Power had no commercial paper outstanding and no outstanding borrowings under its committed lines of credit. 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 BBB- and/or Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $11 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $318 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

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is 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, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.
The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:
                 
    Third Quarter   Year-to-Date
    2009   2009
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (91.5 )   $ (91.9 )
Contracts realized or settled
    41.6       105.5  
Current period changes(a)
    2.9       (60.6 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (47.0 )   $ (47.0 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The increases in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were $44 million and $45 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Alabama Power had a net hedge volume of 40 million mmBtu with a weighted average contract cost approximately $1.17 per mmBtu above market prices, compared to 49 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.89 per mmBtu above market prices and compared to 45 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.12 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the fuel cost recovery clauses.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
                 
    September 30,   December 31,
Asset (Liability) Derivatives   2009   2008
    (in millions)
Regulatory hedges
  $ (47.0 )   $ (91.9 )
Cash flow hedges
           
Not designated
           
 
Total fair value
  $ (47.0 )   $ (91.9 )
 
Energy-related derivative contracts which are designated as 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 clauses. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Unrealized pre-tax gains and losses recognized in income for the three months and nine months ended September 30, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:
                                 
    September 30, 2009
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (47.0 )     (40.3 )     (6.7 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (47.0 )   $ (40.3 )   $ (6.7 )   $  
 
Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Notes 1 and 6 to the financial statements of Alabama Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In March 2009, Alabama Power issued $500 million of Series 2009A 6.00% Senior Notes due March 1, 2039. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program.
In June 2009, Alabama Power incurred obligations related to the issuance of $53 million of The Industrial Development Board of the City of Mobile Pollution Control Revenue Bonds (Alabama Power Barry Plant Project), First Series 2009. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Barry.
In July 2009, Alabama Power issued 3,375,000 shares of common stock to Southern Company at $40 a share ($135 million aggregate purchase price). The proceeds were used for general corporate purposes.
In August 2009, Alabama Power’s $250 million Series BB Floating Rate Senior Notes due August 25, 2009 matured.
Subsequent to September 30, 2009, Alabama Power issued 1,687,500 shares of common stock to Southern Company at $40 a share ($67.5 million aggregate purchase price). The proceeds were used for general corporate purposes.
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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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 2,093,503     $ 2,317,817     $ 5,368,123     $ 5,723,577  
Wholesale revenues, non-affiliates
    108,521       148,933       301,077       443,901  
Wholesale revenues, affiliates
    53,687       106,659       98,520       252,733  
Other revenues
    71,477       70,836       199,623       200,043  
 
                       
Total operating revenues
    2,327,188       2,644,245       5,967,343       6,620,254  
 
                       
Operating Expenses:
                               
Fuel
    830,283       859,778       2,083,662       2,181,000  
Purchased power, non-affiliates
    86,450       192,293       219,220       358,047  
Purchased power, affiliates
    158,864       247,845       528,505       748,622  
Other operations and maintenance
    358,821       379,314       1,102,876       1,139,910  
Depreciation and amortization
    122,740       162,325       464,931       472,137  
Taxes other than income taxes
    86,620       91,587       243,876       242,358  
 
                       
Total operating expenses
    1,643,778       1,933,142       4,643,070       5,142,074  
 
                       
Operating Income
    683,410       711,103       1,324,273       1,478,180  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    23,200       20,887       66,267       72,625  
Interest income
    611       1,416       1,644       3,253  
Interest expense, net of amounts capitalized
    (95,309 )     (86,201 )     (293,124 )     (256,266 )
Other income (expense), net
    (4,127 )     (3,671 )     (8,316 )     (5,593 )
 
                       
Total other income and (expense)
    (75,625 )     (67,569 )     (233,529 )     (185,981 )
 
                       
Earnings Before Income Taxes
    607,785       643,534       1,090,744       1,292,199  
Income taxes
    215,720       237,358       378,030       453,438  
 
                       
Net Income
    392,065       406,176       712,714       838,761  
Dividends on Preferred and Preference Stock
    4,345       4,345       13,036       13,036  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 387,720     $ 401,831     $ 699,678     $ 825,725  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 387,720     $ 401,831     $ 699,678     $ 825,725  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(430), $(874), $(156), and $(890), respectively
    (682 )     (1,386 )     (247 )     (1,410 )
Reclassification adjustment for amounts included in net income, net of tax of $2,350, $574, $6,520, and $1,269, respectively
    3,725       911       10,336       2,012  
 
                       
Total other comprehensive income (loss)
    3,043       (475 )     10,089       602  
 
                       
Comprehensive Income
  $ 390,763     $ 401,356     $ 709,767     $ 826,327  
 
                       
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,  
    2009     2008  
    (in thousands)  
Operating Activities:
               
Net income
  $ 712,714     $ 838,761  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    566,741       561,986  
Deferred income taxes and investment tax credits
    111,035       97,752  
Deferred revenues
    (37,210 )     96,521  
Deferred expenses
    (39,570 )     (26,325 )
Allowance for equity funds used during construction
    (66,267 )     (72,625 )
Pension, postretirement, and other employee benefits
    16,713       35,067  
Hedge settlements
    (16,167 )     (20,486 )
Insurance cash surrender value
    22,381       (73 )
Other, net
    21,131       (14,926 )
Changes in certain current assets and liabilities —
               
-Receivables
    3,648       (284,992 )
-Fossil fuel stock
    (245,777 )     5,302  
-Prepaid income taxes
    (20,694 )     5,185  
-Other current assets
    505       (19,982 )
-Accounts payable
    40,719       (51,661 )
-Accrued taxes
    131,432       151,112  
-Accrued compensation
    (105,097 )     (18,839 )
-Other current liabilities
    35,575       30,285  
 
           
Net cash provided from operating activities
    1,131,812       1,312,062  
 
           
Investing Activities:
               
Property additions
    (1,778,030 )     (1,419,885 )
Distribution of restricted cash from pollution control revenue bonds
    22,077       22,197  
Nuclear decommissioning trust fund purchases
    (889,049 )     (362,565 )
Nuclear decommissioning trust fund sales
    841,763       355,685  
Nuclear decommissioning trust securities lending collateral
    43,824        
Cost of removal, net of salvage
    (41,709 )     (29,798 )
Change in construction payables, net of joint owner portion
    45,828       (22,264 )
Other investing activities
    7,519       (30,543 )
 
           
Net cash used for investing activities
    (1,747,777 )     (1,487,173 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (103,634 )     172,789  
Proceeds —
               
Capital contributions from parent company
    923,840       259,750  
Pollution control revenue bonds issuances
    416,510       94,935  
Senior notes issuances
    500,000       500,000  
Other long-term debt issuances
    1,100       300,000  
Redemptions —
               
Pollution control revenue bonds
    (327,310 )     (118,555 )
Senior notes
    (332,841 )     (122,427 )
Payment of preferred and preference stock dividends
    (13,121 )     (12,668 )
Payment of common stock dividends
    (554,175 )     (540,900 )
Other financing activities
    (12,674 )     (9,357 )
 
           
Net cash provided from financing activities
    497,695       523,567  
 
           
Net Change in Cash and Cash Equivalents
    (118,270 )     348,456  
Cash and Cash Equivalents at Beginning of Period
    132,739       15,392  
 
           
Cash and Cash Equivalents at End of Period
  $ 14,469     $ 363,848  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $28,443 and $30,112 capitalized for 2009 and 2008, respectively)
  $ 239,290     $ 216,572  
Income taxes (net of refunds)
  $ 115,436     $ 228,792  
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   2009     2008  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 14,469     $ 132,739  
Restricted cash and cash equivalents
    4,729       22,381  
Receivables —
               
Customer accounts receivable
    618,710       554,219  
Unbilled revenues
    186,742       147,978  
Under recovered regulatory clause revenues
    352,978       338,780  
Joint owner accounts receivable
    64,690       43,858  
Other accounts and notes receivable
    56,068       54,041  
Affiliated companies
    9,103       13,091  
Accumulated provision for uncollectible accounts
    (13,927 )     (10,732 )
Fossil fuel stock, at average cost
    730,535       484,757  
Materials and supplies, at average cost
    364,685       356,537  
Vacation pay
    65,898       71,217  
Prepaid income taxes
    130,682       65,987  
Other regulatory assets, current
    89,596       118,961  
Other current assets
    115,782       63,464  
 
           
Total current assets
    2,790,740       2,457,278  
 
           
Property, Plant, and Equipment:
               
In service
    25,024,035       23,975,262  
Less accumulated provision for depreciation
    9,426,743       9,101,474  
 
           
Plant in service, net of depreciation
    15,597,292       14,873,788  
Nuclear fuel, at amortized cost
    305,081       278,412  
Construction work in progress
    2,044,835       1,434,989  
 
           
Total property, plant, and equipment
    17,947,208       16,587,189  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    64,809       57,163  
Nuclear decommissioning trusts, at fair value
    594,954       460,430  
Miscellaneous property and investments
    38,673       40,945  
 
           
Total other property and investments
    698,436       558,538  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    594,974       572,528  
Deferred under recovered regulatory clause revenues
    317,780       425,609  
Other regulatory assets, deferred
    1,285,487       1,449,352  
Other deferred charges and assets
    197,428       265,174  
 
           
Total deferred charges and other assets
    2,395,669       2,712,663  
 
           
Total Assets
  $ 23,832,053     $ 22,315,668  
 
           
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   2009     2008  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 253,668     $ 280,443  
Notes payable
    253,461       357,095  
Accounts payable —
               
Affiliated
    208,455       260,545  
Other
    602,484       422,485  
Customer deposits
    197,539       186,919  
Accrued taxes —
               
Accrued income taxes
    148,100       70,916  
Unrecognized tax benefits
    157,512       128,712  
Other accrued taxes
    237,638       278,172  
Accrued interest
    106,454       79,432  
Accrued vacation pay
    49,248       57,643  
Accrued compensation
    38,450       135,191  
Liabilities from risk management activities
    59,287       113,432  
Other cost of removal obligations, current
    241,866        
Other regulatory liabilities, current
    94,688       60,330  
Other current liabilities
    127,518       75,846  
 
           
Total current liabilities
    2,776,368       2,507,161  
 
           
Long-term Debt
    7,284,759       7,006,275  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    3,317,030       3,064,580  
Deferred credits related to income taxes
    131,869       140,933  
Accumulated deferred investment tax credits
    245,927       256,218  
Employee benefit obligations
    898,669       882,965  
Asset retirement obligations
    716,370       688,019  
Other cost of removal obligations
    85,792       396,947  
Other regulatory liabilities, deferred
    42,997       115,865  
Other deferred credits and liabilities
    103,210       111,505  
 
           
Total deferred credits and other liabilities
    5,541,864       5,657,032  
 
           
Total Liabilities
    15,602,991       15,170,468  
 
           
Preferred Stock
    44,991       44,991  
 
           
Preference Stock
    220,966       220,966  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - 9,261,500 shares
    398,473       398,473  
Paid-in capital
    4,584,001       3,655,731  
Retained earnings
    3,003,292       2,857,789  
Accumulated other comprehensive loss
    (22,661 )     (32,750 )
 
           
Total common stockholder’s equity
    7,963,105       6,879,243  
 
           
Total Liabilities and Stockholder’s Equity
  $ 23,832,053     $ 22,315,668  
 
           
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 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008
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 energy sales in the midst of the current economic downturn, 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, capital expenditures, and fuel prices. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. On August 27, 2009, the Georgia PSC approved an accounting order that will allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations over the 18-month period ending December 31, 2010 in lieu of filing a request for a base rate increase. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters – Retail Rate Matters” herein for additional information.
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 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(14.1)
  (3.5)   $(126.0)   (15.3)
 
Georgia Power’s third quarter 2009 net income after dividends on preferred and preference stock was $387.7 million compared to $401.8 million for the corresponding period in 2008. Georgia Power’s year-to-date 2009 net income after dividends on preferred and preference stock was $699.7 million compared to $825.7 million for the corresponding period in 2008. These decreases were primarily due to lower commercial and industrial base revenues resulting from the recessionary economy that were partially offset by cost containment activities and the amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC. Also contributing to the year-to-date 2009 decrease was a charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees resigned from their positions effective March 31, 2009.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(224.3)
  (9.7)   $(355.5)   (6.2)
 
In the third quarter 2009, retail revenues were $2.09 billion compared to $2.32 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $5.37 billion compared to $5.72 billion for the corresponding period in 2008.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2009   2009
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 2,317.8             $ 5,723.6          
Estimated change in —
                               
Rates and pricing
    (43.7 )     (1.9 )     (64.2 )     (1.1 )
Sales growth (decline)
    (24.9 )     (1.1 )     (87.2 )     (1.5 )
Weather
    (17.0 )     (0.7 )     (12.5 )     (0.2 )
Fuel cost recovery
    (138.7 )     (6.0 )     (191.6 )     (3.4 )
 
Retail – current year
  $ 2,093.5       (9.7 )%   $ 5,368.1       (6.2 )%
 
Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased revenues from market-response rates to large commercial and industrial customers of $101.2 million and $204.6 million for the third quarter and year-to-date 2009, respectively, partially offset by increased recognition of environmental compliance cost recovery revenues of $57.5 million and $140.4 million for the third quarter and year-to-date 2009, respectively, in accordance with the 2007 Retail Rate Plan.
Revenues attributable to changes in sales declined in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008. These decreases were primarily due to the recessionary economy, partially offset by a 0.2% increase in retail customers. Weather-adjusted residential KWH sales increased 0.3%, weather-adjusted commercial KWH sales decreased 1.9%, and weather-adjusted industrial KWH sales decreased 7.9% for the third quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted residential KWH sales increased 0.1%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales decreased 12.2% year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted industrial KWH sales decreased due to a broad decline in demand across all industrial segments, most significantly in the chemical, primary metals, textiles, and stone, clay, and glass sectors, for the third quarter and year-to-date 2009.
Revenues resulting from changes in weather decreased in the third quarter and for year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $138.7 million in the third quarter 2009 and by $191.6 million year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased KWH sales and lower purchased power and natural gas prices, partially offset by higher coal prices. 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 impact net income.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(40.4)
  (27.1)   $(142.8)   (32.2)
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Georgia Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation.
In the third quarter 2009, wholesale revenues from non-affiliates were $108.5 million compared to $148.9 million for the corresponding period in 2008. The decrease was due to a 44.9% decrease in KWH sales due to lower demand.
For year-to-date 2009, wholesale revenues from non-affiliates were $301.1 million compared to $443.9 million for the corresponding period in 2008. The decrease was due to a 47.8% decrease in KWH sales due to lower demand.
Wholesale Revenues – Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(53.0)
  (49.7)   $(154.2)   (61.0)
 
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 2009, wholesale revenues from affiliates were $53.7 million compared to $106.7 million for the corresponding period in 2008. The decrease was due to lower natural gas prices partially offset by a 29.7% increase in KWH sales.
For year-to-date 2009, wholesale revenues from affiliates were $98.5 million compared to $252.7 million for the corresponding period in 2008. The decrease was due to lower natural gas prices and a 29.9% decrease in KWH sales due to lower demand.

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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 2009   Year-to-Date 2009
    vs.   vs.
    Third Quarter 2008   Year-to-Date 2008
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $(29.5)   (3.4)   $(97.4)   (4.5)
Purchased power – non-affiliates
  (105.8)   (55.0)   (138.8)   (38.8)
Purchased power – affiliates
  (88.9)   (35.9)   (220.1)   (29.4)
             
Total fuel and purchased power expenses
  $(224.2)       $(456.3)    
             
*   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 2009, total fuel and purchased power expenses were $1.08 billion compared to $1.30 billion for the corresponding period in 2008. The decrease was due to a $130.1 million decrease related to fewer KWHs generated and purchased and a $94.1 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.
For year-to-date 2009, total fuel and purchased power expenses were $2.83 billion compared to $3.29 billion for the corresponding period in 2008. The decrease was due to a $263.0 million decrease related to fewer KWHs generated and purchased and a $193.3 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.
Details of Georgia Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter   Percent                   Percent
Average Cost   2009   2008   Change   Year-to-Date 2009   Year-to-Date 2008   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    3.50       3.32       5.4       3.39       3.07       10.4  
Purchased power
    6.43       8.87       (27.5 )     6.14       8.39       (26.8 )
 
In the third quarter 2009, fuel expense was $830.3 million compared to $859.8 million for the corresponding period in 2008. The decrease was due to a decrease of 34.8% in natural gas prices and a decrease of 6.0% in KWHs generated as a result of lower KWH demand, partially offset by an increase of 15.1% in the average cost of coal per KWH generated.
For year-to-date 2009, fuel expense was $2.08 billion compared to $2.18 billion for the corresponding period in 2008. The decrease was due to a decrease of 40.6% in natural gas prices and a decrease of 13.7% in KWHs generated as a result of lower KWH demand, partially offset by an increase of 21.7% in the average cost of coal per KWH generated.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-Affiliates
In the third quarter 2009, purchased power from non-affiliates was $86.5 million compared to $192.3 million for the corresponding period in 2008. The decrease was due to a 28.0% decrease in the average cost of KWH purchased and a 37.5% decrease in the volume of KWHs purchased.
For year-to-date 2009, purchased power from non-affiliates was $219.2 million compared to $358.0 million for the corresponding period in 2008. The decrease was due to a 35.6% decrease in the average cost of KWH purchased and a 4.9% decrease in the volume of KWHs purchased.
Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than 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.
Affiliates
In the third quarter 2009, purchased power from affiliates was $158.9 million compared to $247.8 million for the corresponding period in 2008. The decrease was due to a 26.7% decrease in the average cost per KWH purchased and a 4.7% decrease in the volume of KWHs purchased.
For year-to-date 2009, purchased power from affiliates was $528.5 million compared to $748.6 million for the corresponding period in 2008. The decrease was due to a 23.7% decrease in the average cost of KWH purchased partially offset by a 1.6% increase in the volume of KWHs 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, as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(20.5)
  (5.4)   $(37.0)   (3.2)
 
In the third quarter 2009, other operations and maintenance expenses were $358.8 million compared to $379.3 million for the corresponding period in 2008. The decrease was due to a $9.1 million decrease in power generation, a $7.2 million decrease in transmission and distribution, and a decrease of $6.1 million in customer accounting, service, and sales costs, most of which are related to cost containment activities in an effort to offset the effects of the recessionary economy.
For year-to-date 2009, other operations and maintenance expenses were $1.10 billion compared to $1.14 billion for the corresponding period in 2008. The decrease was due to a $24.3 million decrease in power generation, a $25.5 million decrease in transmission and distribution, and a $20.6 million decrease in customer accounting, service, and sales costs primarily due to the cost containment activities described above, partially offset by a $5.7 million increase in uncollectible accounts, a $2.8 million increase in property insurance, and a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign their positions effective March 31, 2009. In the second and third quarters 2009, approximately two-thirds of the $29.4 million charge was offset by lower salary and employee benefits costs, and the other one-third will be offset during the remainder of the year. This charge is not expected to have a material impact on Georgia Power’s financial statements for the year ending December 31, 2009.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(39.6)
  (24.4)   $(7.2)   (1.5)
 
In the third quarter 2009, depreciation and amortization was $122.7 million compared to $162.3 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $464.9 million compared to $472.1 million for the corresponding period in 2008. These decreases were primarily due to the amortization of $54.0 million of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC, partially offset by increased depreciation due to additional plant in service related to transmission, distribution, and environmental projects.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$2.3
  11.1   $(6.3)   (8.8)
 
In the third quarter 2009, the change in allowance for equity funds used during construction (AFUDC) when compared to the corresponding period in 2008 was not material.
For year-to-date 2009, AFUDC was $66.3 million compared to $72.6 million for the corresponding period in 2008. The decrease was due to a decrease in the average cost of construction work in progress balances for year-to-date 2009 compared to the corresponding period in 2008 as a result of projects completed in 2008.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$9.1
  10.6   $36.8   14.4
 
In the third quarter 2009, interest expense, net of amounts capitalized was $95.3 million compared to $86.2 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $293.1 million compared to $256.3 million for the corresponding period in 2008. These increases were primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes and pollution control bonds in the last 12 months to fund Georgia Power’s ongoing construction program, partially offset by lower average interest rates on existing variable rate debt.
Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(21.7)
  (9.1)   $(75.4)   (16.6)
 
In the third quarter 2009, income taxes were $215.7 million compared to $237.4 million for the corresponding period in 2008. For year-to-date 2009, income taxes were $378.0 million compared to $453.4 million for the corresponding period in 2008. These decreases were primarily due to lower pre-tax net income.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery will 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. 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.
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 to 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 September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters 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 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 September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

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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 the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Georgia Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges 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 Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.
Global Climate Issues
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Georgia Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.
In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable

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energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Georgia Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
FERC and Georgia PSC Matters
Market-Based Rate Authority
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail 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. In May 2008, the Georgia PSC approved an additional increase of approximately $222 million effective June 2008. On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009 and, on August 27, 2009, the Georgia PSC approved an additional delay in the filing date to no later than December 15, 2009 (with new rates to be effective April 1, 2010). As of September 30, 2009, Georgia Power had a total under recovered fuel cost balance of approximately $671 million compared to $764 million at December 31, 2008.
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, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.
Retail Rate Matters
Under the 2007 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. In connection with the 2007 Retail Rate Plan, the Georgia PSC ordered that Georgia Power file its next general base rate case by July 1, 2010; however, the 2007 Retail Rate Plan provided that Georgia Power may file for a general base rate increase in the event its projected retail ROE falls below 10.25%.

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The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations.
On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, if Georgia Power does not file for a retail base rate increase in 2009, Georgia Power will be entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009. Through September 30, 2009, Georgia Power has amortized $54 million of the regulatory liability. In addition, Georgia Power will be entitled to amortize up to two-thirds of the regulatory liability ($216 million) in 2010. In the event Georgia Power files for a retail base rate increase prior to July 1, 2010, then the amortization of the regulatory liability in 2010 would be reduced by one-sixth for each month that such rate case is filed prior to July 1, 2010.
Furthermore, the amortization of the regulatory liability is limited to only the amount that would allow Georgia Power to earn a retail ROE not more than 9.75% in 2009 and 10.15% in 2010. In addition, Georgia Power may not file for a base rate increase prior to July 1, 2010 unless economic conditions beyond its control continue to reduce Georgia Power’s projected retail ROE and in no event unless Georgia Power’s projected retail ROE for 2009 or 2010 is less than 9.25% after taking into consideration amortization of the regulatory liability.
On July 21, 2009, the Georgia PSC accepted Georgia Power’s offer to bring a total of 178 MWs of the Block 5 and 6 capacity (which covers small portions of Plants Gaston, McManus, Mitchell, and Wilson) into retail rate base for the remaining life of the assets as existing wholesale contracts expire in 2011-2016. Similar treatment for approximately 78 MWs of Plant Scherer Unit 3 capacity for 2015-2031 was approved on September 15, 2009.
Construction
Nuclear
See Note (B) to the Condensed Financial Statements under “Construction Projects — Nuclear” herein for information regarding the potential expansion of Plant Vogtle.
On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.5 billion.
On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.
On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. Georgia Power believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions. The ultimate outcome of this matter cannot be determined at this time.

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On August 26, 2009, the NRC issued the Early Site Permit and Limited Work Authorization for Plant Vogtle Units 3 and 4. Excavation for the new units is in progress.
On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4. The ultimate outcome of this matter cannot be determined at this time.
On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any change to the estimated construction cost as certified by the Georgia PSC in March 2009. The Georgia PSC will conduct hearings between November 2009 and January 2010 in review of this report and is scheduled to render its decision on February 18, 2010. The ultimate outcome of this matter cannot be determined at this time.
There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot now be determined.
Other
On March 17, 2009, the Georgia PSC approved Georgia Power’s request to convert Plant Mitchell from coal-fueled to wood biomass-fueled at an in-service cost of approximately $103 million. The conversion is expected to be completed in 2012. The Georgia PSC also approved Georgia Power’s plan to install additional environmental controls at Plants Branch and Yates.
On August 10, 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. On September 30, 2009, Georgia Power amended the report. As amended, the report includes a request for an increase in the certified costs to construct Plant McDonough. The Georgia PSC will conduct hearings between December 2009 and February 2010 in review of the amended report and is scheduled to render its decision on March 16, 2010.
Nuclear Relicensing
The NRC operating licenses for Plant Vogtle Units 1 and 2 were scheduled to expire in January 2027 and February 2029, respectively. In June 2007, Georgia Power filed an application with the NRC to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. On June 3, 2009, the NRC approved the extension of the licenses as requested.
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Georgia Power. Georgia Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $120 million and $150 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been

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granted, of which $51 million relates to Georgia Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Georgia Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.
Other Matters
Georgia Power is involved in various other matters being litigated, regulatory matters, and certain tax-related issues 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 United States. In particular, personal injury 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 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 liabilities, if any, arising from such current proceedings would have a material adverse 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 accounting principles generally accepted in the United States. 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, and Unbilled Revenues.
New Accounting Standards
Variable Interest Entities
In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Georgia Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
Georgia Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Georgia Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Georgia Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Georgia Power currently average less than 3/8 of 1% per year. Georgia Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Georgia Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.
Georgia Power’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Georgia Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Georgia Power does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.
Net cash provided from operating activities totaled $1.1 billion for the first nine months of 2009, compared to $1.3 billion for the corresponding period in 2008. The $180.3 million decrease in cash provided from operating activities in the first nine months of 2009 was primarily due to the $126 million decrease in net income, a reduction in deferred environmental revenues of approximately $140 million, and an increase in fuel inventory additions of approximately $251 million, partially offset by reductions in accounts receivable. Net cash used for investing activities totaled $1.7 billion for the first nine months of 2009, compared to $1.5 billion for the corresponding period in 2008. The increase was primarily due to gross property additions to utility plant. Net cash provided from financing activities totaled $497.7 million for the first nine months of 2009, compared to $523.6 million for the corresponding period in 2008. The $25.9 million decrease was primarily due to higher redemptions of long-term debt, partially offset by higher capital contributions from Southern Company in 2009.
Significant balance sheet changes for the first nine months of 2009 include an increase of $1.4 billion in total property, plant, and equipment.
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, 2010 to fund maturities of long-term debt. 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 nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency

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of construction labor, equipment, and materials; 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
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Georgia Power has primarily utilized funds 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.
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, 2009 approximately $14.5 million of cash and cash equivalents and approximately $1.7 billion of unused credit arrangements with banks. 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. Of the unused credit arrangements in place at September 30, 2009, $595 million expire in 2010 and $1.1 billion expire in 2012. Georgia Power expects to renew its credit facilities, as needed, prior to expiration.
Credit arrangements provide liquidity support to Georgia Power’s purchase obligations related to variable rate pollution control revenue bonds and commercial paper borrowings. At September 30, 2009, Georgia Power had $901 million of variable rate pollution control revenue bonds outstanding. Georgia Power may 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, 2009, Georgia Power had approximately $253 million of commercial paper outstanding. 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, emissions allowances, energy price risk management, and construction of new generation. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $35 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.2 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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On September 2, 2009, Moody’s affirmed the credit ratings of Georgia Power’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Georgia Power’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook. On September 4, 2009, Fitch affirmed Georgia Power’s senior unsecured notes and commercial paper ratings of A+/F1, respectively, but revised Georgia Power’s rating outlook to negative.
Market Price Risk
Georgia Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 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, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.
The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:
                 
    Third Quarter   Year-to-Date
    2009   2009
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (125.4 )   $ (113.2 )
Contracts realized or settled
    56.5       130.6  
Current period changes(a)
    3.0       (83.3 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (65.9 )   $ (65.9 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The changes in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were increases of $60 million and $47 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Georgia Power had a net hedge volume of 68 million mmBtu with a weighted average contract cost approximately $0.96 per mmBtu above market prices, compared to 75 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.69 per mmBtu above market prices and compared to 59 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.96 per mmBtu above market prices. The natural gas hedge settlements are recovered through the fuel cost recovery mechanism.

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At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
                 
    September 30,   December 31,
Asset (Liability) Derivatives   2009   2008
    (in millions)
Regulatory hedges
  $ (65.9 )   $ (113.2 )
Not designated
           
 
Total fair value
  $ (65.9 )   $ (113.2 )
 
Energy-related derivative contracts which are designated as regulatory hedges relate to Georgia 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 mechanism. 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.
Unrealized pre-tax gains and losses recognized in income for the three months and nine months ended September 30, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:
                                 
    September 30, 2009
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (65.9 )     (52.4 )     (13.3 )     (0.2 )
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (65.9 )   $ (52.4 )   $ (13.3 )   $ (0.2 )
 
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Georgia Power in Item 7 and Notes 1 and 6 to the financial statements of Georgia Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.
Financing Activities
In February 2009, Georgia Power issued $500 million of Series 2009A 5.95% Senior Notes due February 1, 2039. The proceeds were used to repay at maturity $150 million aggregate principal amount of Series U Floating Rate Senior Notes due February 7, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Georgia Power settled $100 million of hedges related to the Series 2009A issuance at a loss of approximately $16 million, and this loss will be amortized to interest expense, in earnings, together with a previously settled loss of approximately $2 million, over 10 years.

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In July 2009, Georgia Power incurred obligations in connection with the issuance of $154.3 million of variable rate pollution control revenue bonds. The proceeds of the bonds were used to retire $154.3 million of fixed rate pollution control revenue bonds.
In August 2009, Georgia Power’s $125 million Series V 4.10% Senior Notes due August 15, 2009 matured.
In August 2009, Georgia Power redeemed its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.
In September 2009, Georgia Power incurred obligations in connection with the issuance of variable rate pollution control revenue bonds totaling $262.2 million. The proceeds of $89.2 million of the variable rate pollution control revenue bonds were used to fund the acquisition, construction, installation, and equipping costs of certain solid waste disposal facilities located at Plant Scherer. The proceeds from the remaining $173 million were used to retire Bartow County (Georgia Power Plant Bowen Project) First, Second and Third Series 2007 variable rate pollution control revenue bonds totaling $173 million.
Subsequent to September 30, 2009, Georgia Power entered into forward starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The total notional amount of the swaps is $200 million, and the swaps have been designated as a cash flow hedge.
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,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 329,597     $ 359,652     $ 858,038     $ 871,834  
Wholesale revenues, non-affiliates
    25,752       26,194       70,418       76,902  
Wholesale revenues, affiliates
    3,661       20,036       19,748       89,500  
Other revenues
    18,631       15,959       54,816       45,007  
 
                       
Total operating revenues
    377,641       421,841       1,003,020       1,083,243  
 
                       
Operating Expenses:
                               
Fuel
    163,302       185,003       435,050       501,129  
Purchased power, non-affiliates
    9,991       14,057       20,480       23,269  
Purchased power, affiliates
    29,399       41,136       58,020       66,564  
Other operations and maintenance
    57,422       65,223       194,896       197,428  
Depreciation and amortization
    23,452       22,295       69,828       66,205  
Taxes other than income taxes
    26,683       25,088       72,120       66,587  
 
                       
Total operating expenses
    310,249       352,802       850,394       921,182  
 
                       
Operating Income
    67,392       69,039       152,626       162,061  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    6,810       2,673       17,335       6,196  
Interest income
    129       914       423       2,332  
Interest expense, net of amounts capitalized
    (9,264 )     (10,491 )     (29,003 )     (32,165 )
Other income (expense), net
    (266 )     (355 )     (1,369 )     (1,365 )
 
                       
Total other income and (expense)
    (2,591 )     (7,259 )     (12,614 )     (25,002 )
 
                       
Earnings Before Income Taxes
    64,801       61,780       140,012       137,059  
Income taxes
    22,042       22,886       45,341       48,542  
 
                       
Net Income
    42,759       38,894       94,671       88,517  
Dividends on Preference Stock
    1,551       1,551       4,652       4,652  
 
                       
Net Income After Dividends on Preference Stock
  $ 41,208     $ 37,343     $ 90,019     $ 83,865  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preference Stock
  $ 41,208     $ 37,343     $ 90,019     $ 83,865  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(414), $-, $(414), and $(1,077), respectively
    (659 )           (659 )     (1,715 )
Reclassification adjustment for amounts included in net income, net of tax of $105, $104, $314, and $261, respectively
    166       167       500       416  
 
                       
Total other comprehensive income (loss)
    (493 )     167       (159 )     (1,299 )
 
                       
Comprehensive Income
  $ 40,715     $ 37,510     $ 89,860     $ 82,566  
 
                       
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,  
    2009     2008  
    (in thousands)  
Operating Activities:
               
Net income
  $ 94,671     $ 88,517  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    74,407       69,926  
Deferred income taxes
    (2,177 )     24,850  
Allowance for equity funds used during construction
    (17,335 )     (6,196 )
Pension, postretirement, and other employee benefits
    1,123       1,413  
Stock option expense
    793       656  
Tax benefit of stock options
    8       200  
Hedge settlements
          (5,220 )
Other, net
    (4,017 )     (4,116 )
Changes in certain current assets and liabilities —
               
-Receivables
    40,388       (75,430 )
-Fossil fuel stock
    (54,511 )     (26,408 )
-Materials and supplies
    (1,411 )     7,135  
-Prepaid income taxes
    416       (3,929 )
-Property damage cost recovery
    10,831       20,038  
-Other current assets
    2,178       2,371  
-Accounts payable
    (13,022 )     (2,154 )
-Accrued taxes
    14,593       3,825  
-Accrued compensation
    (7,364 )     (3,063 )
-Other current liabilities
    8,627       (2,057 )
 
           
Net cash provided from operating activities
    148,198       90,358  
 
           
Investing Activities:
               
Property additions
    (330,776 )     (232,398 )
Investment in restricted cash from pollution control revenue bonds
    (49,188 )      
Distribution of restricted cash from pollution control revenue bonds
    28,144        
Cost of removal, net of salvage
    (6,758 )     (5,246 )
Construction payables
    (11,721 )     13,830  
Other investing activities
    (5,445 )     (3,956 )
 
           
Net cash used for investing activities
    (375,744 )     (227,770 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (101,589 )     57,813  
Proceeds —
               
Common stock issued to parent
    135,000        
Capital contributions from parent company
    3,461       75,304  
Gross excess tax benefit of stock options
    22       283  
Pollution control revenue bonds
    130,400        
Senior notes
    140,000        
Other long-term debt issuances
          110,000  
Redemptions —
               
Senior notes
    (1,033 )     (974 )
Payment of preference stock dividends
    (4,652 )     (4,507 )
Payment of common stock dividends
    (66,975 )     (61,275 )
Other financing activities
    (1,635 )     (2,135 )
 
           
Net cash provided from financing activities
    232,999       174,509  
 
           
Net Change in Cash and Cash Equivalents
    5,453       37,097  
Cash and Cash Equivalents at Beginning of Period
    3,443       5,348  
 
           
Cash and Cash Equivalents at End of Period
  $ 8,896     $ 42,445  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $6,909 and $2,470 capitalized for 2009 and 2008, respectively)
  $ 29,123     $ 27,940  
Income taxes (net of refunds)
  $ 43,423     $ 37,353  
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   2009     2008  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 8,896     $ 3,443  
Restricted cash and cash equivalents
    21,043        
Receivables —
               
Customer accounts receivable
    91,613       69,531  
Unbilled revenues
    57,723       48,742  
Under recovered regulatory clause revenues
    31,878       98,644  
Other accounts and notes receivable
    3,897       7,201  
Affiliated companies
    1,724       8,516  
Accumulated provision for uncollectible accounts
    (1,896 )     (2,188 )
Fossil fuel stock, at average cost
    160,704       108,129  
Materials and supplies, at average cost
    38,247       36,836  
Other regulatory assets, current
    22,841       38,908  
Prepaid expenses
    28,670       20,363  
Other current assets
    2,043       5,292  
 
           
Total current assets
    467,383       443,417  
 
           
Property, Plant, and Equipment:
               
In service
    2,890,230       2,785,561  
Less accumulated provision for depreciation
    1,005,256       971,464  
 
           
Plant in service, net of depreciation
    1,884,974       1,814,097  
Construction work in progress
    614,808       391,987  
 
           
Total property, plant, and equipment
    2,499,782       2,206,084  
 
           
Other Property and Investments
    15,902       15,918  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    35,225       24,220  
Other regulatory assets, deferred
    169,900       170,836  
Other deferred charges and assets
    24,698       18,550  
 
           
Total deferred charges and other assets
    229,823       213,606  
 
           
Total Assets
  $ 3,212,890     $ 2,879,025  
 
           
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   2009     2008  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 140,000     $  
Notes payable
    38,341       148,239  
Accounts payable —
               
Affiliated
    46,633       50,304  
Other
    72,379       90,381  
Customer deposits
    31,463       28,017  
Accrued taxes —
               
Accrued income taxes
    11,038       39,983  
Other accrued taxes
    22,869       11,855  
Accrued interest
    10,634       8,959  
Accrued compensation
    8,303       15,667  
Other regulatory liabilities, current
    19,076       4,602  
Liabilities from risk management activities
    13,531       26,928  
Other current liabilities
    20,781       29,047  
 
           
Total current liabilities
    435,048       453,982  
 
           
Long-term Debt
    978,982       849,265  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    296,385       254,354  
Accumulated deferred investment tax credits
    10,053       11,255  
Employee benefit obligations
    96,827       97,389  
Other cost of removal obligations
    189,077       180,325  
Other regulatory liabilities, deferred
    40,737       28,597  
Other deferred credits and liabilities
    83,523       83,768  
 
           
Total deferred credits and other liabilities
    716,602       655,688  
 
           
Total Liabilities
    2,130,632       1,958,935  
 
           
Preference Stock
    97,998       97,998  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - September 30, 2009: 3,142,717 shares
               
- December 31, 2008: 1,792,717 shares
    253,060       118,060  
Paid-in capital
    515,830       511,547  
Retained earnings
    220,461       197,417  
 
           
Accumulated other comprehensive loss
    (5,091 )     (4,932 )
 
           
Total common stockholder’s equity
    984,260       822,092  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,212,890     $ 2,879,025  
 
           
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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008
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 energy sales in the midst of the current economic downturn, 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 the need to recover these increasing costs 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.
RESULTS OF OPERATIONS
Net Income
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$3.9
  10.3   $6.1   7.3
 
Gulf Power’s net income after dividends on preference stock for the third quarter 2009 was $41.2 million compared to $37.3 million for the corresponding period in 2008. The increase was primarily due to increased allowance for equity funds used during construction (AFUDC), which is non-taxable, decreased other operations and maintenance expenses, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales.
Gulf Power’s net income after dividends on preference stock for year-to-date 2009 was $90.0 million compared to $83.9 million for the corresponding period in 2008. The increase was primarily due to increased AFUDC, which is non-taxable, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales.
Retail Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(30.1)
  (8.4)   $(13.8)   (1.6)
 
In the third quarter 2009, retail revenues were $329.6 million compared to $359.7 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $858.0 million compared to $871.8 million for the corresponding period in 2008.

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GULF 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
    2009   2009
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 359.7             $ 871.8          
Estimated change in –
                               
Rates and pricing
    10.2       2.9       25.5       2.9  
Sales growth (decline)
    (0.6 )     (0.2 )     (4.1 )     (0.5 )
Weather
    (6.0 )     (1.7 )     (8.9 )     (1.0 )
Fuel and other cost recovery
    (33.7 )     (9.4 )     (26.3 )     (3.0 )
 
Retail – current year
  $ 329.6       (8.4 )%   $ 858.0       (1.6 )%
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to increased revenue associated with higher projected environmental compliance costs in 2009. Annually, Gulf Power petitions the Florida PSC for recovery of projected 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 declined in the third quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential customers increased 3.3% despite a reduction in the number of customers, primarily due to an increase in per customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 1.4% primarily due to decreased per customer usage and a decrease in the number of customers driven by the recession. KWH energy sales to industrial customers decreased 29.3% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.
Revenues attributable to changes in sales declined year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential customers increased 1.5% despite a decrease in the number of customers, primarily due to an increase in per customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 1.1% primarily due to a decrease in per customer usage and a decrease in the number of customers driven by the recession. KWH energy sales to industrial customers decreased 24.2% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.
Revenues attributable to changes in weather decreased in the third quarter and year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.
Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 due to overall decreased customer usage primarily resulting from decreased industrial usage. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and revenues related to the recovery of storm damage restoration 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 impact on net income. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters – Retail Regulatory Matters” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Storm Damage Cost Recovery” and “Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change) (change in millions) (% change)
$(0.4)
  (1.7)   $(6.5)   (8.4)
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Gulf Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from non-affiliates are predominantly unit power sales under long-term contracts to other Florida 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.
In the third quarter 2009, wholesale revenues from non-affiliates were $25.8 million compared to $26.2 million for the corresponding period in 2008. The decrease was primarily due to lower energy revenues related to a 7.7% decrease in KWH sales resulting from reduced customer demand primarily caused by the recessionary economy.
For year-to-date 2009, wholesale revenues from non-affiliates were $70.4 million compared to $76.9 million for the corresponding period in 2008. The decrease was primarily due to lower energy revenues related to a 17.1% decrease in KWH sales resulting from reduced customer demand primarily caused by the recessionary economy.
Wholesale Revenues – Affiliates
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(16.4)
  (81.7)   $(69.8)   (77.9)
 
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 2009, wholesale revenues from affiliates were $3.6 million compared to $20.0 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 63.0% decrease in KWH sales and a 50.6% decrease in price related to lower Power Pool interchange energy rates.
For year-to-date 2009, wholesale revenues from affiliates were $19.7 million compared to $89.5 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 66.3% decrease in KWH sales and a 34.6% decrease in price related to lower Power Pool interchange energy rates.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$2.7
  16.7   $9.8   21.8
 
In the third quarter 2009, other revenues were $18.6 million compared to $15.9 million for the corresponding period in 2008. For year-to-date 2009, other revenues were $54.8 million compared to $45.0 million for the corresponding period in 2008. These increases were primarily due to other energy services and higher franchise fees. The increased revenues from other energy services did not have a material impact on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income.
Fuel and Purchased Power Expenses
                          
    Third Quarter 2009   Year-to-Date 2009
    vs.   vs.
    Third Quarter 2008   Year-to-Date 2008
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $(21.7)   (11.7)   $(66.1)   (13.2)
Purchased power – non-affiliates
  (4.1)   (28.9)   (2.8)   (12.0)
Purchased power – affiliates
  (11.7)   (28.5)   (8.5)   (12.8)
             
Total fuel and purchased power expenses
  $(37.5)       $(77.4)    
             
* 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 2009, total fuel and purchased power expenses were $202.6 million compared to $240.1 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was primarily due to a $24.9 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas and a $12.6 million decrease related to total KWHs generated and purchased.
For year-to-date 2009, total fuel and purchased power expenses were $513.5 million compared to $590.9 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was primarily due to a $50.4 million decrease related to total KWHs generated and purchased and a $27.0 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas.
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 – “FERC and Florida PSC Matters – Retail Regulatory Matters” herein for additional information.
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   2009   2008   Change   2009   2008   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    4.59       4.54       1.1       4.46       4.20       6.2  
Purchased power
    7.98       13.09       (39.0 )     6.78       11.07       (38.8 )
 

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In the third quarter 2009, fuel expense was $163.3 million compared to $185.0 million for the corresponding period in 2008. The decrease was due to a decrease of 42.3% in the average cost of natural gas prices and a decrease of 13.9% in KWHs generated as a result of lower demand, partially offset by an increase of 17.5% in the average cost of coal per KWH generated.
For year-to-date 2009, fuel expense was $435.0 million compared to $501.1 million for the corresponding period in 2008. The decrease was due to a decrease of 39.7% in the average cost of natural gas prices and a decrease of 19.0% in KWHs generated as a result of lower demand, partially offset by an increase of 22.5% in the average cost of coal per KWH generated.
Non-Affiliates
In the third quarter 2009, purchased power from non-affiliates was $9.9 million compared to $14.0 million for the corresponding period in 2008. The decrease was primarily related to a 51.8% decrease in the volume of KWHs purchased, partially offset by a 77.7% increase in average cost per KWH purchased.
For year-to-date 2009, purchased power from non-affiliates was $20.5 million compared to $23.3 million for the corresponding period in 2008. The decrease was primarily related to an 11.2% decrease in the volume of KWHs purchased, partially offset by a 15.3% increase in average cost per KWH purchased.
Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than 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 2009, purchased power from affiliates was $29.4 million compared to $41.1 million for the corresponding period in 2008. The decrease was primarily related to a 56.8% decrease in average cost per KWH purchased, partially offset by a 66.5% increase in the volume of KWHs purchased from lower-priced Power Pool resources.
For year-to-date 2009, purchased power from affiliates was $58.0 million compared to $66.5 million for the corresponding period in 2008. The decrease was primarily related to a 52.8% decrease in average cost per KWH purchased, partially offset by an 85.5% increase in the volume of KWHs purchased from lower-priced Power Pool resources.
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, as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(7.8)
  (12.0)   $(2.5)   (1.3)
 
In the third quarter 2009, other operations and maintenance expenses were $57.4 million compared to $65.2 million for the corresponding period in 2008. The decrease was primarily due to an $8.0 million decrease in storm recovery costs and a $1.9 million decrease in maintenance at generation facilities, partially offset by $1.9 million in increased expense from other energy services. The decreased storm recovery costs and the increased

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expense from other energy services did not have a material impact on earnings since they were offset by associated revenues.
For year-to-date 2009, other operations and maintenance expenses were $194.9 million compared to $197.4 million for the corresponding period in 2008. The decrease was primarily due to a $9.7 million decrease in storm recovery costs, partially offset by a $7.4 million increase in other energy services. The decreased storm recovery costs and the increased expense from other energy services did not have a material impact on earnings since they were offset by associated revenues.
Depreciation and Amortization
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$1.2
  5.2   $3.6   5.5
 
In the third quarter 2009, depreciation and amortization was $23.5 million compared to $22.3 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $69.8 million compared to $66.2 million for the corresponding period in 2008. These increases were primarily due to net additions to generation and distribution facilities.
Taxes Other Than Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$1.6
  6.4   $5.5   8.3
 
In the third quarter 2009, taxes other than income taxes were $26.7 million compared to $25.1 million for the corresponding period in 2008. For year-to-date 2009, taxes other than income taxes were $72.1 million compared to $66.6 million for the corresponding period in 2008. These increases were primarily due to increases in franchise fees and gross receipt taxes, which have no impact on net income.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$4.1
  154.8   $11.1   179.8
 
In the third quarter 2009, AFUDC was $6.8 million compared to $2.7 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $17.3 million compared to $6.2 million for the corresponding period in 2008. These increases were primarily due to the construction of environmental control projects.
Interest Income
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(0.8)
  (85.9)   $(1.9)   (81.9)
 
In the third quarter 2009, interest income was $0.1 million compared to $0.9 million for the corresponding period in 2008. For year-to-date 2009, interest income was $0.4 million compared to $2.3 million for the corresponding period in 2008. These decreases were primarily due to decreases in interest received related to the recovery of financing costs associated with the fuel clause.

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Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(1.2)
  (11.7)   $(3.2)   (9.8)
 
In the third quarter 2009, interest expense, net of amounts capitalized was $9.3 million compared to $10.5 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $29.0 million compared to $32.2 million for the corresponding period in 2008. These decreases were primarily the result of an increase in capitalization of AFUDC related to the construction of environmental control projects.
Income Taxes
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)   (% change)   (change in millions)   (% change)
$(0.8)
  (3.7)   $(3.2)   (6.6)
 
In the third quarter 2009, income taxes were $22.1 million compared to $22.9 million for the corresponding period in 2008. The decrease was primarily due to an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable.
For year-to-date 2009, income taxes were $45.3 million compared to $48.5 million for the corresponding period in 2008. The decrease was primarily due to an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable, and state tax credits, partially offset by higher pre-tax income.
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 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. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery will 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. 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.

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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 to 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 September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters 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 September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and 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 the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Gulf Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges 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 the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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Global Climate Issues
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Gulf Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.
In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Gulf Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
FERC and Florida PSC Matters
Market-Based Rate Authority
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding

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initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced higher than expected fuel costs for coal and natural gas. 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 if an adjustment to the fuel cost recovery factor is being requested.
Under recovered fuel costs at September 30, 2009 totaled $26.1 million, compared to $96.7 million at December 31, 2008. 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 would have no significant effect on Gulf Power’s revenues or net income, but would affect cash flow.
On November 4, 2009, the Florida PSC approved Gulf Power’s annual rate clause requests for its purchased power capacity, conservation, and environmental compliance cost recovery factors for 2010. A decision from the Florida PSC on Gulf Power’s annual rate clause request for its 2010 fuel cost recovery factor is expected in December 2009. The net effect of the approved and proposed changes to Gulf Power’s cost recovery factors for 2010 is a 3.9% rate increase for residential customers using 1,000 KWHs per month. The ultimate outcome of this matter cannot now be determined.
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,” respectively, in Item 8 of the Form 10-K for additional information.
Legislation
On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Gulf Power. Gulf Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $13 million and $16 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $15.5 million relates to Gulf Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Gulf Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.
Other Matters
On March 16, 2009, Gulf Power entered into a PPA (the Agreement) with Shell Energy North America (US), L.P. (Shell). Under the terms of the Agreement, Gulf Power will be entitled to all of the capacity and energy from an approximately 885 MW combined cycle power plant (the Plant) located in Autauga County, Alabama that is owned and operated by Tenaska Alabama II Partners, L.P. (Tenaska). Shell is entitled to all of the capacity and energy from the Plant under a 20-year Energy Conversion Agreement between Shell and Tenaska that expires on May 24, 2023. On July 14, 2009, the Florida PSC approved the Agreement. On October 17, 2009, the Florida PSC’s approval became a final, non-appealable order. The Agreement became effective on November 1, 2009. Unless earlier terminated in accordance with its terms, the Agreement will

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terminate on May 24, 2023. Payments under the Agreement will be material. However, these costs have been approved by the Florida PSC for recovery through Gulf Power’s fuel clause and purchased power capacity clause; therefore, no material impact is expected on Gulf Power’s net income.
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 United States. In particular, personal injury 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 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 liabilities, if any, arising from such current proceedings would have a material adverse 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.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements 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, and Unbilled Revenues.
New Accounting Standards
Variable Interest Entities
In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Gulf Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
Gulf Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Gulf Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Gulf Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Gulf Power currently average less than 3/4 of 1% per year. Gulf Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Gulf Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.
Gulf Power’s investments in pension trust funds remained stable during the third quarter 2009. Gulf Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time.
Net cash provided from operating activities totaled $148.2 million for the first nine months of 2009, compared to $90.4 million for the corresponding period in 2008. The $57.8 million increase in cash provided from operating activities was primarily due to a $118.8 million increase in cash from under recovered regulatory clause revenues related to fuel, partially offset by a $28.1 million increase in cash payments for fossil fuel inventory and a $27.0 million decrease in deferred income taxes. Net cash used for investing activities totaled $375.7 million for the first nine months of 2009, compared to $227.8 million for the corresponding period in 2008. The $147.9 million increase was primarily due to gross property additions to utility plant. These additions were primarily related to installation of equipment to comply with environmental requirements. Net cash provided from financing activities totaled $233.0 million for the first nine months of 2009, compared to $174.5 million for the corresponding period in 2008. The $58.5 million increase in cash provided from financing activities was primarily due to the issuances of $140.0 million of senior notes, $135.0 million of common stock to Southern Company, and $130.4 million of pollution control revenue bonds in 2009, partially offset by an issuance of $110.0 million of long-term debt in 2008, a $71.8 million decrease of capital contributions from Southern Company, and a $159.4 million increase in cash payments related to notes payable.
Significant balance sheet changes for the first nine months of 2009 include a net increase of $293.7 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of $140.0 million in senior notes; the issuance of common stock to Southern Company for $135.0 million; the issuance of $130.4 million of pollution control revenue bonds, with a related restricted cash balance of $21.0 million; an increase in fossil fuel stock of $52.6 million; an increase in customer accounts receivable and unbilled revenues of $31.1 million; and a $66.8 million decrease in under recovered regulatory clause revenues primarily related to fuel.

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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, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $140 million will be required through September 30, 2010 to fund maturities of debt. 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 FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; 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 utilized in the past. Recently, Gulf Power has utilized funds from operating cash flows, short-term debt, security offerings, 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 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, 2009 approximately $8.9 million of cash and cash equivalents and $220 million of unused committed lines of credit with banks. Of these credit agreements, $60 million expire in 2009, $160 million expire in 2010, and $70 million of these facilities contain provisions allowing one-year term loans executable at expiration. Subsequent to September 30, 2009, Gulf Power renewed $40 million of its credit facilities that were set to expire in 2009 and extended the maturity dates to 2010. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. 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. 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. Gulf Power may 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, 2009, Gulf Power had $36.9 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.
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, emissions allowances, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $58 million. At September 30, 2009,

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the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $384 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.
On September 2, 2009, Moody’s affirmed the credit ratings of Gulf Power’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Gulf Power’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook. On September 4, 2009, Fitch affirmed Gulf Power’s senior unsecured notes and commercial paper ratings of A+/F1, respectively, and maintained a stable rating outlook for Gulf Power.
Market Price Risk
Gulf Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 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, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Gulf Power continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC. As such, Gulf Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.
The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:
                 
    Third Quarter   Year-to-Date
    2009   2009
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (28.2 )   $ (31.2 )
Contracts realized or settled
    12.5       35.6  
Current period changes(a)
    0.6       (19.5 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (15.1 )   $ (15.1 )
 
(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The increases in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were $13 million and $16 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Gulf Power had a net hedge volume of 12 million mmBtu with a weighted average contract cost approximately $1.23 per mmBtu above market prices, compared to 15 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.95 per mmBtu above market prices and compared to 14 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.24 per mmBtu above market prices. Natural gas hedge settlements are recovered through the fuel cost recovery clause.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:
                 
    September 30,   December 31,
Asset (Liability) Derivatives   2009   2008
    (in millions)
Regulatory hedges
  $ (15.1 )   $ (31.2 )
Not designated
           
 
Total fair value
  $ (15.1 )   $ (31.2 )
 
Energy-related derivative contracts which are designated as 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. 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.
Unrealized pre-tax gains and losses recognized in income for the three months and nine months ended September 30, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:
                                 
            September 30, 2009    
            Fair Value Measurements    
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
            (in millions)        
Level 1
  $     $     $     $  
Level 2
    (15.1 )     (12.0 )     (3.2 )     0.1  
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (15.1 )   $ (12.0 )   $ (3.2 )   $ 0.1  
 
Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and Notes 1 and 6 to the financial statements of Gulf Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.
Financing Activities
On January 22, 2009, Gulf Power issued to Southern Company 1,350,000 shares of Gulf Power common stock, without par value, and realized proceeds of $135 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes, including Gulf Power’s continuous construction program.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In March 2009, Gulf Power incurred obligations related to the issuance of $130.4 million of pollution control revenue bonds. The proceeds are being used for the acquisition, construction, installation, and equipping of certain solid waste disposal facilities located at Plant Crist.
In June 2009, Gulf Power issued $140 million of Series 2009A Floating Rate Senior Notes due June 28, 2010. The proceeds were used to repay a portion of short-term indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.
In July 2009, Gulf Power entered into a forward starting interest rate swap to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swap is $50 million, and the swap has been designated as a cash flow hedge.
Subsequent to September 30, 2009, Gulf Power entered into another forward starting interest rate swap to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swap is $50 million, and the swap has been designated as a cash flow hedge.
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,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 231,894     $ 241,788     $ 608,761     $ 597,298  
Wholesale revenues, non-affiliates
    81,242       106,595       235,089       274,996  
Wholesale revenues, affiliates
    13,404       28,908       30,785       79,833  
Other revenues
    4,140       4,124       11,449       12,636  
 
                       
Total operating revenues
    330,680       381,415       886,084       964,763  
 
                       
Operating Expenses:
                               
Fuel
    148,115       174,300       393,912       443,273  
Purchased power, non-affiliates
    1,666       13,777       7,374       21,458  
Purchased power, affiliates
    21,946       35,421       65,346       78,903  
Other operations and maintenance
    61,138       64,828       182,500       192,969  
Depreciation and amortization
    17,707       17,229       53,382       52,327  
Taxes other than income taxes
    17,033       17,142       48,178       48,993  
 
                       
Total operating expenses
    267,605       322,697       750,692       837,923  
 
                       
Operating Income
    63,075       58,718       135,392       126,840  
Other Income and (Expense):
                               
Interest income
    34       403       829       996  
Interest expense, net of amounts capitalized
    (6,075 )     (4,504 )     (17,091 )     (13,336 )
Other income (expense), net
    474       1,507       3,239       6,025  
 
                       
Total other income and (expense)
    (5,567 )     (2,594 )     (13,023 )     (6,315 )
 
                       
Earnings Before Income Taxes
    57,508       56,124       122,369       120,525  
Income taxes
    22,177       19,474       46,268       42,832  
 
                       
Net Income
    35,331       36,650       76,101       77,693  
Dividends on Preferred Stock
    433       433       1,299       1,299  
 
                       
Net Income After Dividends on Preferred Stock
  $ 34,898     $ 36,217     $ 74,802     $ 76,394  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2009     2008     2009     2008  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred Stock
  $ 34,898     $ 36,217     $ 74,802     $ 76,394  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(27), $1,285, $-, and $(169), respectively
    (44 )     2,075             (272 )
 
                       
Comprehensive Income
  $ 34,854     $ 38,292     $ 74,802     $ 76,122  
 
                       
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,  
    2009     2008  
    (in thousands)  
Operating Activities:
               
Net income
  $ 76,101     $ 77,693  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    58,929       56,026  
Deferred income taxes and investment tax credits, net
    (27,430 )     5,112  
Pension, postretirement, and other employee benefits
    5,817       6,088  
Stock option expense
    822       639  
Tax benefit of stock options
    17       473  
Generation construction screening expense
    (21,955 )     (12,278 )
Other, net
    214       (15,111 )
Changes in certain current assets and liabilities —
               
-Receivables
    48,512       (36,440 )
-Fossil fuel stock
    (42,838 )     (26,810 )
-Materials and supplies
    (1,782 )     (2,961 )
-Prepaid income taxes
    1,061       1,187  
-Other current assets
    (9,783 )     4,098  
-Other accounts payable
    (26,354 )     10,195  
-Accrued taxes
    13,430       (6,998 )
-Accrued compensation
    (10,238 )     (8,066 )
-Other current liabilities
    20,694       17,355  
 
           
Net cash provided from operating activities
    85,217       70,202  
 
           
Investing Activities:
               
Property additions
    (72,661 )     (100,490 )
Cost of removal, net of salvage
    (9,911 )     (3,497 )
Construction payables
    (3,949 )     (5,201 )
Hurricane Katrina capital grant proceeds
          7,314  
Other investing activities
    (2,150 )     2,422  
 
           
Net cash used for investing activities
    (88,671 )     (99,452 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (24,891 )     44,608  
Proceeds —
               
Capital contributions from parent company
    3,330       4,222  
Gross excess tax benefit of stock options
    67       892  
Senior notes issuances
    125,000        
Other long-term debt issuances
          80,000  
Redemptions —
               
Pollution control revenue bonds
          (7,900 )
Senior notes
    (40,000 )      
Payment of preferred stock dividends
    (1,299 )     (1,299 )
Payment of common stock dividends
    (51,375 )     (51,300 )
Other financing activities
    (1,781 )     (1,475 )
 
           
Net cash provided from financing activities
    9,051       67,748  
 
           
Net Change in Cash and Cash Equivalents
    5,597       38,498  
Cash and Cash Equivalents at Beginning of Period
    22,413       4,827  
 
           
Cash and Cash Equivalents at End of Period
  $ 28,010     $ 43,325  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $117 and $113 capitalized for 2009 and 2008, respectively)
  $ 15,824     $ 12,054  
Income taxes (net of refunds)
  $ 48,008     $ 38,710  
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   2009     2008  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 28,010     $ 22,413  
Receivables —
               
Customer accounts receivable
    51,841       40,262  
Unbilled revenues
    28,294       24,798  
Under recovered regulatory clause revenues
          54,994  
Other accounts and notes receivable
    7,097       8,995  
Affiliated companies
    17,414       24,108  
Accumulated provision for uncollectible accounts
    (1,338 )     (1,039 )
Fossil fuel stock, at average cost
    128,375       85,538  
Materials and supplies, at average cost
    28,925       27,143  
Other regulatory assets, current
    55,366       59,220  
Prepaid income taxes
    18,773       1,061  
Other current assets
    17,241       9,837  
 
           
Total current assets
    379,998       357,330  
 
           
Property, Plant, and Equipment:
               
In service
    2,302,812       2,234,573  
Less accumulated provision for depreciation
    936,324       923,269  
 
           
Plant in service, net of depreciation
    1,366,488       1,311,304  
Construction work in progress
    43,162       70,665  
 
           
Total property, plant, and equipment
    1,409,650       1,381,969  
 
           
Other Property and Investments
    7,321       8,280  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    8,860       9,566  
Other regulatory assets, deferred
    184,897       171,680  
Other deferred charges and assets
    25,842       23,870  
 
           
Total deferred charges and other assets
    219,599       205,116  
 
           
Total Assets
  $ 2,016,568     $ 1,952,695  
 
           
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,  
Liabilities and Stockholder’s Equity   2009     2008  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 1,304     $ 41,230  
Notes payable
    1,403       26,293  
Accounts payable —
               
Affiliated
    28,581       36,847  
Other
    41,667       63,704  
Customer deposits
    10,790       10,354  
Accrued taxes —
               
Accrued income taxes
    24,120       8,842  
Other accrued taxes
    40,647       50,700  
Accrued interest
    4,264       3,930  
Accrued compensation
    10,365       20,604  
Other regulatory liabilities, current
    9,783       9,718  
Over recovered regulatory clause liabilities
    20,466        
Liabilities from risk management activities
    22,179       29,291  
Other current liabilities
    17,715       19,144  
 
           
Total current liabilities
    233,284       320,657  
 
           
Long-term Debt
    493,779       370,460  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    222,702       222,324  
Deferred credits related to income taxes
    11,862       14,074  
Accumulated deferred investment tax credits
    13,121       14,014  
Employee benefit obligations
    145,598       142,188  
Other cost of removal obligations
    97,208       96,191  
Other regulatory liabilities, deferred
    55,688       51,340  
Other deferred credits and liabilities
    46,434       52,216  
 
           
Total deferred credits and other liabilities
    592,613       592,347  
 
           
Total Liabilities
    1,319,676       1,283,464  
 
           
Redeemable Preferred Stock
    32,780       32,780  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value —
               
Authorized - 1,130,000 shares
               
Outstanding - 1,121,000 shares
    37,691       37,691  
Paid-in capital
    324,193       319,958  
Retained earnings
    302,228       278,802  
Accumulated other comprehensive income (loss)
           
 
           
Total common stockholder’s equity
    664,112       636,451  
 
           
Total Liabilities and Stockholder’s Equity
  $ 2,016,568     $ 1,952,695  
 
           
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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, 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, capital expenditures, and restoration following major storms. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with reasonable retail rates will continue to challenge Mississippi Power for the foreseeable future.
Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power’s long-term financial success is dependent upon how well it satisfies its customers’ needs, Mississippi Power’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power’s allowed return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Mississippi Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.3)   (3.6)   $(1.6)   (2.1)
 
Mississippi Power’s net income after dividends on preferred stock for the third quarter 2009 was $34.9 million compared to $36.2 million for the corresponding period in 2008. The decrease in net income after dividends on preferred stock for the third quarter 2009 was primarily due to decreases in wholesale energy revenues and total other income and (expense) and an increase in income tax expense. The decrease was partially offset by an increase in retail base revenues primarily resulting from increased sales in the industrial class, an increase in territorial wholesale base revenues due to a wholesale base rate increase and increased demand, as well as a decrease in other operations and maintenance expenses.
Mississippi Power’s net income after dividends on preferred stock for year-to-date 2009 was $74.8 million compared to $76.4 million for the corresponding period in 2008. The decrease in net income after dividends on preferred stock for year-to-date 2009 was primarily due to decreases in wholesale energy revenues and total other income and (expense) and an increase in income tax expense. The decrease was partially offset by an increase in territorial wholesale base revenues primarily resulting from an increase in territorial wholesale base rates and increased demand, as well as a decrease in other operations and maintenance expenses.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2009 vs. Third Quarter 2008   Year-to-Date 2009 vs. Year-to-Date 2008
 
(change in millions)   (% change)   (change in millions)   (% change)
$(9.9)   (4.1)   $11.5   1.9
 
In the third quarter 2009, retail revenues were $231.9 million compared to $241.8 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $608.8 million compared to $597.3 million for the corresponding period in 2008.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2009   2009
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 241.8             $ 597.3          
Estimated change in —