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ALABAMA POWER CO - Quarter Report: 2010 September (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2010
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    
 
       
001-31737
  Gulf Power Company   59-0276810 
 
  (A Florida Corporation)    
 
  One Energy Place    
 
  Pensacola, Florida 32520    
 
  (850) 444-6111    
 
       
001-11229
  Mississippi Power Company   64-0205820 
 
  (A Mississippi Corporation)    
 
  2992 West Beach    
 
  Gulfport, Mississippi 39501    
 
  (228) 864-1211    
 
       
333-98553
  Southern Power Company   58-2598670 
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    

 


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     Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
     Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No o (Response applicable only to The Southern Company at this time.)
     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, 2010  
The Southern Company
  Par Value $5 Per Share     838,671,173  
Alabama Power Company
  Par Value $40 Per Share     30,537,500  
Georgia Power Company
  Without Par Value     9,261,500  
Gulf Power Company
  Without Par Value     3,642,717  
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, 2010
             
        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  
           
        40  
        40  
        41  
        42  
        44  
           
        62  
        62  
        63  
        64  
        66  
           
        86  
        86  
        87  
        88  
        90  
           
        108  
        108  
        109  
        110  
        112  
           
        134  
        134  
        135  
        136  
        138  
        151  
Item 3.       37  
Item 4.       37  
Item 4T.       37  

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2010
             
        Page
        Number
PART II — OTHER INFORMATION
   
 
       
Item 1.         182
Item 1A.         182
Item 2.  
Unregistered Sales of Equity Securities and Use of Proceeds
  Inapplicable
Item 3.  
Defaults Upon Senior Securities
  Inapplicable
Item 5.  
Other Information
  Inapplicable
Item 6.         183
          188

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DEFINITIONS
     
Term   Meaning
2007 Retail Rate Plan
  Georgia Power’s retail rate plan for the years 2008 through 2010
AFUDC
  Allowance for funds used during construction
Alabama Power
  Alabama Power Company
Clean Air Act
  Clean Air Act Amendments of 1990
DOE
  U.S. Department of Energy
Duke Energy
  Duke Energy Corporation
ECO Plan
  Mississippi Power’s Environmental Compliance Overview Plan
EPA
  U.S. Environmental Protection Agency
FERC
  Federal Energy Regulatory Commission
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, 2009
GAAP
  Generally Accepted Accounting Principles
Georgia Power
  Georgia Power Company
Georgia PSC Staff
  Georgia Public Service Commission Public Interest Advocacy Staff
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
NDR
  Alabama Power’s natural disaster reserve
NRC
  Nuclear Regulatory Commission
NSR
  New Source Review
OCI
  Other Comprehensive Income
PEP
  Mississippi Power’s Performance Evaluation Plan
Power Pool
  The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA
  Power Purchase Agreement
PSC
  Public Service Commission
Rate CNP Environmental
  Alabama Power’s certificated new plant for environmental costs
Rate ECR
  Alabama Power’s energy cost recovery rate mechanism
Rate NDR
  Alabama Power’s natural disaster cost recovery rate mechanism
Rate RSE
  Alabama Power’s rate stabilization and equalization plan
registrants
  Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS
  Southern Company Services, Inc.
SEC
  Securities and Exchange Commission

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access to sources of capital, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, 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, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
  current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits;
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
  variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;
  available sources and costs of fuels;
  effects of inflation;
  ability to control costs and avoid cost overruns during the development and construction of facilities;
  investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trusts;
  advances in technology;
  state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
  regulatory approvals and actions related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;
  regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees;
  the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
  internal restructuring or other restructuring options that may be pursued;
  potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
  the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
  the ability to obtain new short- and long-term contracts with wholesale customers;
  the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
  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 influenzas, or other similar occurrences;
  the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
  the effect of accounting pronouncements issued periodically by standard setting bodies; and
  other factors discussed elsewhere herein and in other reports (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,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 4,572,617     $ 3,997,659     $ 11,603,017     $ 10,355,330  
Wholesale revenues
    565,932       519,122       1,580,748       1,408,286  
Other electric revenues
    160,960       139,869       438,547       391,070  
Other revenues
    20,403       24,832       62,336       78,267  
 
                       
Total operating revenues
    5,319,912       4,681,482       13,684,648       12,232,953  
 
                       
Operating Expenses:
                               
Fuel
    1,969,683       1,733,527       5,243,826       4,588,932  
Purchased power
    209,287       166,791       464,226       407,623  
Other operations and maintenance
    1,020,370       820,889       2,846,785       2,523,184  
MC Asset Recovery litigation settlement
                      202,000  
Depreciation and amortization
    426,797       332,117       1,136,730       1,099,216  
Taxes other than income taxes
    235,260       212,882       661,521       620,851  
 
                       
Total operating expenses
    3,861,397       3,266,206       10,353,088       9,441,806  
 
                       
Operating Income
    1,458,515       1,415,276       3,331,560       2,791,147  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    45,162       51,061       139,853       141,173  
Interest income
    5,463       6,013       15,057       17,791  
Leveraged lease income (losses)
    5,839       6,578       12,639       24,695  
Gain on disposition of lease termination
                      26,300  
Loss on extinguishment of debt
                      (17,184 )
Interest expense, net of amounts capitalized
    (225,138 )     (226,345 )     (666,289 )     (684,902 )
Other income (expense), net
    (14,481 )     (10,466 )     (37,185 )     (27,293 )
 
                       
Total other income and (expense)
    (183,155 )     (173,159 )     (535,925 )     (519,420 )
 
                       
Earnings Before Income Taxes
    1,275,360       1,242,117       2,795,635       2,271,727  
Income taxes
    441,927       435,947       925,110       828,833  
 
                       
Consolidated Net Income
    833,433       806,170       1,870,525       1,442,894  
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
  $ 817,238     $ 789,975     $ 1,821,940     $ 1,394,309  
 
                       
Common Stock Data:
                               
Earnings per share (EPS) -
                               
Basic EPS
  $ 0.98     $ 0.99     $ 2.20     $ 1.77  
Diluted EPS
  $ 0.97     $ 0.99     $ 2.19     $ 1.76  
Average number of shares of common stock outstanding (in thousands)
                               
Basic
    835,953       798,418       828,947       789,675  
Diluted
    841,835       800,178       833,220       791,259  
Cash dividends paid per share of common stock
  $ 0.4550     $ 0.4375     $ 1.3475     $ 1.2950  
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,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Consolidated net income
  $ 1,870,525     $ 1,442,894  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    1,376,511       1,310,854  
Deferred income taxes
    572,862       (14,565 )
Deferred revenues
    (76,976 )     (40,781 )
Allowance for equity funds used during construction
    (139,853 )     (141,173 )
Leveraged lease income (losses)
    (12,639 )     (24,695 )
Gain on disposition of lease termination
          (26,300 )
Loss on extinguishment of debt
          17,184  
Pension, postretirement, and other employee benefits
    51,792       42,775  
Stock based compensation expense
    28,307       20,850  
Hedge settlements
    1,530       (16,167 )
Generation construction screening costs
    (50,554 )     (21,955 )
Other, net
    10,126       32,321  
Changes in certain current assets and liabilities —
               
-Receivables
    (319,384 )     319,286  
-Fossil fuel stock
    220,017       (361,520 )
-Materials and supplies
    (10,880 )     (40,811 )
-Other current assets
    (48,186 )     (50,977 )
-Accounts payable
    (82,318 )     (210,459 )
-Accrued taxes
    118,131       238,988  
-Accrued compensation
    93,323       (273,349 )
-Other current liabilities
    (75,733 )     157,384  
 
           
Net cash provided from operating activities
    3,526,601       2,359,784  
 
           
Investing Activities:
               
Property additions
    (2,893,812 )     (3,179,009 )
Investment in restricted cash from pollution control revenue bonds
    (12 )     (49,528 )
Distribution of restricted cash from pollution control revenue bonds
    24,811       90,088  
Nuclear decommissioning trust fund purchases
    (695,855 )     (1,066,688 )
Nuclear decommissioning trust fund sales
    671,600       1,019,401  
Proceeds from property sales
    6,607       339,911  
Cost of removal, net of salvage
    (83,930 )     (85,022 )
Change in construction payables
    (83,678 )     110,265  
Other investing activities
    48,285       (35,766 )
 
           
Net cash used for investing activities
    (3,005,984 )     (2,856,348 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (289,202 )     118,124  
Proceeds —
               
Long-term debt issuances
    2,796,000       2,216,010  
Common stock issuances
    610,465       668,529  
Redemptions —
               
Long-term debt
    (1,871,485 )     (1,229,484 )
Payment of common stock dividends
    (1,113,948 )     (1,018,928 )
Payment of dividends on preferred and preference stock of subsidiaries
    (48,921 )     (48,675 )
Other financing activities
    (34,513 )     (18,732 )
 
           
Net cash provided from financing activities
    48,396       686,844  
 
           
Net Change in Cash and Cash Equivalents
    569,013       190,280  
Cash and Cash Equivalents at Beginning of Period
    689,722       416,581  
 
           
Cash and Cash Equivalents at End of Period
  $ 1,258,735     $ 606,861  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $61,165 and $59,849 capitalized for 2010 and 2009, respectively)
  $ 589,129     $ 589,919  
Income taxes (net of refunds)
  $ 277,716     $ 644,541  
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   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 1,258,735     $ 689,722  
Restricted cash and cash equivalents
    18,336       43,135  
Receivables —
               
Customer accounts receivable
    1,435,968       953,222  
Unbilled revenues
    443,838       394,492  
Under recovered regulatory clause revenues
    226,820       333,459  
Other accounts and notes receivable
    261,104       374,670  
Accumulated provision for uncollectible accounts
    (29,741 )     (24,568 )
Fossil fuel stock, at average cost
    1,222,690       1,446,984  
Materials and supplies, at average cost
    808,446       793,847  
Vacation pay
    144,607       145,049  
Prepaid expenses
    529,823       508,338  
Other regulatory assets, current
    222,531       166,549  
Other current assets
    66,295       48,558  
 
           
Total current assets
    6,609,452       5,873,457  
 
           
Property, Plant, and Equipment:
               
In service
    56,029,332       53,587,853  
Less accumulated depreciation
    19,947,881       19,121,271  
 
           
Plant in service, net of depreciation
    36,081,451       34,466,582  
Nuclear fuel, at amortized cost
    660,856       593,119  
Construction work in progress
    4,457,402       4,170,596  
 
           
Total property, plant, and equipment
    41,199,709       39,230,297  
 
           
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,142,566       1,070,117  
Leveraged leases
    620,674       610,252  
Miscellaneous property and investments
    279,015       282,974  
 
           
Total other property and investments
    2,042,255       1,963,343  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,182,050       1,047,452  
Unamortized debt issuance expense
    192,296       208,346  
Unamortized loss on reacquired debt
    265,867       254,936  
Deferred under recovered regulatory clause revenues
    291,736       373,245  
Other regulatory assets, deferred
    2,652,520       2,701,910  
Other deferred charges and assets
    458,895       392,880  
 
           
Total deferred charges and other assets
    5,043,364       4,978,769  
 
           
Total Assets
  $ 54,894,780     $ 52,045,866  
 
           
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   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 1,983,593     $ 1,112,705  
Notes payable
    348,399       639,199  
Accounts payable
    1,160,993       1,329,448  
Customer deposits
    333,876       330,582  
Accrued taxes —
               
Accrued income taxes
    77,995       13,005  
Unrecognized tax benefits
    177,969       165,645  
Other accrued taxes
    459,839       398,384  
Accrued interest
    238,944       218,188  
Accrued vacation pay
    182,454       183,911  
Accrued compensation
    351,859       247,950  
Liabilities from risk management activities
    175,938       124,648  
Other regulatory liabilities, current
    190,760       528,147  
Other current liabilities
    311,793       292,016  
 
           
Total current liabilities
    5,994,412       5,583,828  
 
           
Long-term Debt
    18,198,225       18,131,244  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    7,069,518       6,454,822  
Deferred credits related to income taxes
    238,734       248,232  
Accumulated deferred investment tax credits
    472,174       447,650  
Employee benefit obligations
    2,336,393       2,304,344  
Asset retirement obligations
    1,247,760       1,201,343  
Other cost of removal obligations
    1,202,491       1,091,425  
Other regulatory liabilities, deferred
    295,545       277,932  
Other deferred credits and liabilities
    502,756       345,888  
 
           
Total deferred credits and other liabilities
    13,365,371       12,371,636  
 
           
Total Liabilities
    37,558,008       36,086,708  
 
           
Redeemable Preferred Stock of Subsidiaries
    374,496       374,496  
 
           
Stockholders’ Equity:
               
Common Stockholders’ Equity:
               
Common stock, par value $5 per share —
               
Authorized — September 30, 2010: 1.5 billion shares
               
— December 31, 2009: 1.0 billion shares
               
Issued — September 30, 2010: 839,145,736 Shares
               
— December 31, 2009: 820,151,801 Shares
               
Treasury — September 30, 2010: 474,563 Shares
               
— December 31, 2009: 505,116 Shares
               
Par value
    4,195,666       4,100,742  
Paid-in capital
    3,550,130       2,994,245  
Treasury, at cost
    (13,962 )     (14,797 )
Retained earnings
    8,594,861       7,884,922  
Accumulated other comprehensive loss
    (71,747 )     (87,778 )
 
           
Total Common Stockholders’ Equity
    16,254,948       14,877,334  
Preferred and Preference Stock of Subsidiaries
    707,328       707,328  
 
           
Total Stockholders’ Equity
    16,962,276       15,584,662  
 
           
Total Liabilities and Stockholders’ Equity
  $ 54,894,780     $ 52,045,866  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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Table of Contents

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,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Consolidated Net Income
  $ 833,433     $ 806,170     $ 1,870,525     $ 1,442,894  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $1,025, $(1,356), $544, and $(2,338), respectively
    1,595       (2,151 )     814       (3,815 )
Reclassification adjustment for amounts included in net income, net of tax of $2,438, $4,610, $9,114, and $13,073, respectively
    3,839       7,339       14,413       20,807  
Marketable securities:
                               
Change in fair value, net of tax of $(2,007), $(1,056), $(391), and $239, respectively
    (3,086 )     (1,359 )     (290 )     2,310  
Pension and other post retirement benefit plans:
                               
Reclassification adjustment for amounts included in net income, net of tax of $230, $222, $690, and $665, respectively
    365       350       1,094       1,049  
 
                       
Total other comprehensive income (loss)
    2,713       4,179       16,031       20,351  
 
                       
Dividends on preferred and preference stock of subsidiaries
    (16,195 )     (16,195 )     (48,585 )     (48,585 )
 
                       
Comprehensive Income
  $ 819,951     $ 794,154     $ 1,837,971     $ 1,414,660  
 
                       
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
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, telecommunications, and renewable energy projects. 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 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$27.2   3.5   $427.6   30.7
 
Southern Company’s third quarter 2010 net income after dividends on preferred and preference stock of subsidiaries was $817.2 million ($0.98 per share) compared to $790.0 million ($0.99 per share) for third quarter 2009. The increase for the third quarter 2010 when compared to the corresponding period in 2009 was primarily the result of increases in revenues due to warmer weather, revenues associated with increases in rates under Alabama Power’s Rate RSE and Rate CNP Environmental that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for the third quarter 2010 was partially offset by increases in operations and maintenance expenses, which includes an additional NDR accrual at Alabama Power, reduced amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.
Southern Company’s year-to-date 2010 net income after dividends on preferred and preference stock of subsidiaries was $1.82 billion ($2.20 per share) compared to $1.39 billion ($1.77 per share) for year-to-date 2009. The increase for year-to-date 2010 when compared to the corresponding period in 2009 was primarily the result of a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increases in revenues due to warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010, the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, revenues associated with increases in rates under Alabama Power’s Rate RSE and Rate CNP Environmental that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for year-to-date 2010 was partially offset by increases in operations and maintenance expenses, which includes an additional NDR accrual at Alabama Power, a gain in 2009 on the early termination of two international leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$574.9   14.4   $1,247.7   12.0
 
In the third quarter 2010, retail revenues were $4.57 billion compared to $4.00 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $11.60 billion compared to $10.36 billion for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 3,997.7             $ 10,355.3          
Estimated change in —
                               
Rates and pricing
    162.1       4.1       296.7       2.9  
Sales growth (decline)
    8.0       0.2       50.4       0.5  
Weather
    197.3       4.9       377.1       3.6  
Fuel and other cost recovery
    207.5       5.2       523.5       5.0  
 
Retail – current year
  $ 4,572.6       14.4 %   $ 11,603.0       12.0 %
 
Revenues associated with changes in rates and pricing increased in the third quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to Rate RSE and Rate CNP Environmental increases at Alabama Power, higher contributions from market-driven rates for sales to industrial customers at Georgia Power, recovery of environmental compliance costs at Gulf Power, and increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with the 2007 Retail Rate Plan.
Revenues attributable to changes in sales increased in the third quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 due to increases in weather-adjusted retail KWH energy sales of 1.4% and 2.5%, respectively. For the third quarter 2010, weather-adjusted residential KWH energy sales increased 0.1%, weather-adjusted commercial KWH energy sales decreased 0.8%, and weather-adjusted industrial KWH energy sales increased 5.7%. For year-to-date 2010, weather-adjusted residential KWH energy sales increased 0.9%, weather-adjusted commercial KWH energy sales decreased 0.7%, and weather-adjusted industrial KWH energy sales increased 8.2%. Increased demand in the primary metals, chemicals, and transportation sectors were the main contributors to the increases in weather-adjusted industrial KWH energy sales for the third quarter and year-to-date 2010.
Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.
Fuel and other cost recovery revenues increased $207.5 million in the third quarter 2010 and $523.5 million for year-to-date 2010 when compared to the corresponding periods in 2009. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$46.8   9.0   $172.5   12.2
 
Wholesale energy sales will vary depending on the market cost of available energy compared to the cost of Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the third quarter 2010, wholesale revenues were $565.9 million compared to $519.1 million for the corresponding period in 2009. The increase was primarily due to higher energy and capacity revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010.
For year-to-date 2010, wholesale revenues were $1.58 billion compared to $1.41 billion for the corresponding period in 2009. This increase was primarily due to higher energy and capacity revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more favorable weather year-to-date 2010 compared to the corresponding period in 2009. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010.
Other Electric Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$21.1   15.1   $47.4   12.1
 
In the third quarter 2010, other electric revenues were $161.0 million compared to $139.9 million for the corresponding period in 2009. This increase was primarily the result of a $15.2 million increase in transmission revenues and a $3.1 million increase in co-generation revenues due to increased sales volume.
For year-to-date 2010, other electric revenues were $438.5 million compared to $391.1 million for the corresponding period in 2009. This increase was primarily the result of a $25.7 million increase in transmission revenues, a $10.7 million increase in co-generation revenues due to increased sales volume, a $4.1 million increase in rents from electric property, and a $2.3 million increase in outdoor lighting revenues.
Revenues from co-generation and other energy services are generally offset by related expenses and do not have a significant effect on net income.
Other Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(4.4)   (17.8)   $(16.0)   (20.4)
 
In the third quarter 2010, other revenues were $20.4 million compared to $24.8 million for the corresponding period in 2009. The decrease was primarily the result of a $4.3 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, other revenues were $62.3 million compared to $78.3 million for the corresponding period in 2009. The decrease was primarily the result of a $15.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010     Year-to-Date 2010  
    vs.     vs.  
    Third Quarter 2009     Year-to-Date 2009  
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
    $236.2       13.6       $654.9       14.3  
Purchased power
        42.5       25.5           56.6       13.9  
                         
Total fuel and purchased power expenses
    $278.7               $711.5          
                         
*   Fuel includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.
Fuel and purchased power expenses for the third quarter 2010 were $2.18 billion compared to $1.90 billion for the corresponding period in 2009. The increase was primarily the result of a $208.5 million increase related to total KWHs generated and purchased and a $70.2 million increase in the average cost of fuel and purchased power. The increase in total fuel and purchased power expenses resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.
For year-to-date 2010, fuel and purchased power expenses were $5.71 billion compared to $5.00 billion for the corresponding period in 2009. The increase was primarily the result of a $402.9 million increase related to total KWHs generated and purchased and a $308.6 million increase in the average cost of fuel and purchased power. The increase in total fuel and purchased power expenses resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.
Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not have a significant effect on net income. See FUTURE EARNINGS POTENTIAL — “State PSC Matters — Retail Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly affect net income.
Details of Southern Company’s cost of generation and purchased power are as follows:
                                                 
Average Cost   Third Quarter
2010
  Third Quarter
2009
  Percent
Change
  Year-to-Date
2010
  Year-to-Date
2009
  Percent
Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    3.55       3.42       3.8       3.55       3.39       4.7  
Purchased power
    8.03       8.00       0.4       7.13       6.20       15.0  
 
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.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$199.5   24.3   $323.6   12.8
 
In the third quarter 2010, other operations and maintenance expenses were $1.02 billion compared to $820.9 million for the corresponding period in 2009. The increase was primarily the result of a $42.2 million increase in fossil, hydro, and nuclear expenses, a $31.4 million increase in commodity and labor costs, a $79.5 million increase in transmission and distribution expenses, which includes an additional accrual of $40.0 million to the NDR at Alabama Power, a $37.2 million increase in administrative and general expenses, and a $9.2 million increase in customer service and sales expenses.
For year-to-date 2010, other operations and maintenance expenses were $2.85 billion compared to $2.52 billion for the corresponding period in 2009. The increase was primarily the result of a $112.1 million increase in fossil, hydro, and nuclear expenses, a $69.4 million increase in commodity and labor costs, a $108.2 million increase in transmission and distribution expenses, which includes an additional accrual of $40.0 million to the NDR at Alabama Power, a $30.4 million increase in administrative and general expenses, and a $3.5 million increase in customer service and sales expenses.
See FUTURE EARNINGS POTENTIAL — “State PSC Matters — Alabama Power Retail Regulatory Matters — Natural Disaster Cost Recovery” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Alabama Power — Natural Disaster Cost Recovery” herein for additional information on the NDR.
MC Asset Recovery Litigation Settlement
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(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 and required MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. In June 2009, the case was dismissed with prejudice. See Note (B) to the Condensed Financial Statements under “Mirant Matters” herein for additional information.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$94.7   28.5   $37.5   3.4
 
In the third quarter 2010, depreciation and amortization was $426.8 million compared to $332.1 million for the corresponding period in 2009. The increase was primarily due to the amortization of $5.0 million in the third quarter 2010 compared to $54.0 million in the third quarter 2009 of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, as well as additional depreciation on plant in service related to environmental, transmission, and distribution projects.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, depreciation and amortization was $1.14 billion compared to $1.10 billion for the corresponding period in 2009. The increase was primarily the result of additional depreciation on plant in service related to environmental, transmission, and distribution projects. The increase was partially offset by the amortization of $119.3 million in 2010 compared to $54.0 million in 2009 of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC.
See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Cost of Removal” for additional information on the amortization of the other cost of removal regulatory liability.
Taxes Other Than Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$22.4   10.5   $40.6   6.6
 
In the third quarter 2010, taxes other than income taxes were $235.3 million compared to $212.9 million for the corresponding period in 2009. This increase was primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in ad valorem taxes, and increases in payroll taxes.
For year-to-date 2010, taxes other than income taxes were $661.5 million compared to $620.9 million for the corresponding period in 2009. This increase was primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in ad valorem taxes, and increases in payroll taxes.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(5.9)   (11.6)   $(1.3)   (0.9)
 
In the third quarter 2010, AFUDC equity was $45.2 million compared to $51.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $139.9 million compared to $141.2 million for the corresponding period in 2009. The third quarter and year-to-date 2010 decreases were primarily due to the completion of environmental projects at Alabama Power and Gulf Power. These decreases were partially offset by increases in construction related to three new combined cycle units, two new nuclear generating units, and ongoing environmental and transmission projects at Georgia Power.
Leveraged Lease Income
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.8)   (11.2)   $(12.1)   (48.8)
 
In the third quarter 2010, leveraged lease income was $5.8 million compared to $6.6 million for the corresponding period in 2009. The decrease when compared to the corresponding period in 2009 was not material.
For year-to-date 2010, leveraged lease income was $12.6 million compared to $24.7 million for the corresponding period in 2009. This decrease was primarily related to the early termination of two leveraged lease investments in the second quarter 2009.

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Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gain on Disposition of Lease Termination
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(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.
Loss on Extinguishment of Debt
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(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 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 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.2)   (0.5)   $(18.6)   (2.7)
 
In the third quarter 2010, interest expense, net of amounts capitalized was $225.1 million compared to $226.3 million for the corresponding period in 2009. The decrease when compared to the corresponding period in 2009 was not material.
For year-to-date 2010, interest expense, net of amounts capitalized was $666.3 million compared to $684.9 million for the corresponding period in 2009. The decrease was primarily due to a $24.8 million decrease related to lower average interest rates on variable-rate debt, an $18.7 million decrease in other interest charges, and a $1.3 million decrease related to higher capitalized interest. Partially offsetting this decrease was a $26.2 million increase associated with $1.04 billion in additional debt outstanding at September 30, 2010 when compared to September 30, 2009.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$6.0   1.4   $96.3   11.6
 
In the third quarter 2010, income taxes were $441.9 million compared to $435.9 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in the third quarter 2010, partially offset by state investment tax credits at Georgia Power, and tax benefits associated with the construction of a biomass facility at Southern Power.
For year-to-date 2010, income taxes were $925.1 million compared to $828.8 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in 2010, partially offset by a decrease in uncertain tax positions at Georgia Power related to state income tax credits that remain subject to litigation, state investment tax credits at Georgia Power, and tax benefits associated with the construction of a biomass facility at Southern Power.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See FUTURE EARNINGS POTENTIAL — “Income Tax Matters — Georgia State Income Tax Credits” and Note (B) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. 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.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power is alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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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 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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time.
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 information regarding proposed sulfur dioxide (SO2) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO2, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Southern Company’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern

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states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and nitrogen oxides (NOx) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including each of the states in Southern Company’s service territory, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
These regulations could result in significant additional compliance and operational 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.
Coal Combustion Byproducts
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Southern Company in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.
The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.
State PSC Matters
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent years, the traditional operating companies have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $505 million at September 30, 2010. Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2010, had a total over recovered fuel balance of approximately $102 million. At December 31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power were approximately $667 million and Alabama Power and Mississippi Power had a total over recovered fuel balance of $229 million. Fuel cost recovery 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 balances. 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 under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Alabama Power Retail Regulatory Matters
Nuclear Outage Accounting Order
On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.

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The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.
Natural Disaster Cost Recovery
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities, referred to as the NDR.
On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.
In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.
Georgia Power Retail Regulatory Matters
Rate Plans
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Georgia Power” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and “— Cost of Removal” in Item 8 of the Form 10-K for additional information regarding the 2007 Retail Rate Plan.
On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.
In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1,

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2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.
Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:
  §   Continuation of a plus or minus 100 basis point range for ROE.
 
  §   Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
 
      The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.
 
  §   Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
 
  §   Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
 
  §   Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.
These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.

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Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.
The final outcome of these matters cannot now be determined.
Fuel Cost Recovery
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 under “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Legislation” of Southern Company in Item 7 of the Form 10-K for additional information.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company and the traditional operating companies have been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Southern Company. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Southern Company cannot be determined at this time.

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Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding, to be matched by Southern Company, will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. See Note 5 to the financial statements of Southern Company under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $243 million. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Southern Company has estimated the cash flow reduction to tax payments for 2010 to be approximately $309 million.
Construction Projects
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including units at Southern Power, proposed new nuclear units, and a proposed IGCC facility, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the

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financial statements of Southern Company under “Construction Program” in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and “Retail Regulatory Matters — Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” and “State PSC Matters — Mississippi Power— Integrated Coal Gasification Combined Cycle” herein for additional information.
On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4), effective January 1, 2011.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein 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.
The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Southern Company’s service territory.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with 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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at September 30, 2010. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $3.5 billion for the first nine months of 2010, an increase of $1.2 billion from the corresponding period in 2009. Significant changes in operating cash flow for the first nine months of 2010 compared to the corresponding period in 2009 include an increase in net income as previously discussed, a reduction in fossil fuel stock, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $3.0 billion for the first nine months of 2010, an increase of $150 million from the corresponding period in 2009. The increase was due to proceeds received on sales of property in 2009. Net cash provided from financing activities totaled $48 million for the first nine months of 2010, a decrease of $638 million from the corresponding period in 2009, primarily due to fewer issuances of securities in the first nine months of 2010 and a reduction in notes payable outstanding. 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 2010 include an increase in cash and cash equivalents of $569 million and an increase of $2.0 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 equity of $1.4 billion.
The market price of Southern Company’s common stock at September 30, 2010 was $37.24 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $19.38 per share, representing a market-to-book ratio of 192%, compared to $33.32, $18.15, and 184%, respectively, at the end of 2009. The dividend for the third quarter 2010 was $0.4550 per share compared to $0.4375 per share in the third quarter 2009.
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 program, scheduled maturities of long-term debt, interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2 billion will be required through September 30, 2011 to fund maturities and announced repurchases and redemptions of long-term debt. Georgia Power met its obligations to repurchase $462.5 million in pollution control revenue bonds subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. Gulf Power met its obligations to redeem $75 million in senior notes subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Southern Company’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2010, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those utilized in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company.
However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.
On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.
In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance the DOE will issue federal loan guarantees to Mississippi Power.
Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities), to meet liquidity needs. At September 30, 2010, Southern Company and its subsidiaries had approximately $1.3 billion of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks. Of the cash and cash equivalents, approximately $1.1 billion was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $126 million expire in 2010, $1.4 billion expire in 2011, and $3.2 billion expire in 2012. Of the credit arrangements expiring in 2010 and 2011, $81 million contain provisions allowing two-year term loans executable at expiration and $922 million contain provisions allowing one-year term loans executable at expiration. At September 30, 2010, approximately $1.8 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011. 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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, 2010, the Southern Company system had approximately $345 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the third quarter 2010, Southern Company had an average of $814 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $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. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time.
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, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $483 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.
On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of the preferred stock, preference stock, and long-term debt payable to affiliated trusts of the traditional operating companies decreased from A to A- at Alabama Power and Georgia Power, from A- to BBB+ at Gulf Power, and from A+ to A at Mississippi Power. These ratings are not applicable to the collateral requirements described above.
On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Southern Company (senior unsecured to Baa1 from A3), Georgia Power (senior unsecured to A3 from A2), Gulf Power (senior unsecured to A3 from A2) and Mississippi Power (senior unsecured to A2 from A1). Moody’s also announced that it had downgraded the short-term ratings of Southern Company and a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Georgia Power, Gulf Power, and Mississippi Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Georgia Power, Gulf Power, and Mississippi Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Georgia Power (to Baa2 from Baa1), Gulf Power (to Baa2 from Baa1), and Mississippi Power (to Baa1 from A3). Moody’s also downgraded the trust preferred securities rating of Georgia Power to Baa1 from A3. All of these companies have stable ratings outlooks from Moody’s.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On September 3, 2010, Fitch downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A+ from AA- and issuer default rating to A from A+). Fitch also announced that it had downgraded the short-term ratings of Mississippi Power to F1 from F1+. In addition, Fitch announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A+ from AA- and the preferred stock ratings of Mississippi Power to A- from A. Fitch announced that the ratings outlook for Mississippi Power is stable. Also, Fitch announced that the ratings outlook of Southern Company had been revised to negative.
Market Price Risk
Southern Company’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 2010, 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, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, Southern Company had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.
The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (202 )   $ (178 )
Contracts realized or settled
    49       160  
Current period changes(a)
    (96 )     (231 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (249 )   $ (249 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $47 million and a decrease of $71 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Southern Company had a net hedge volume of 138 million mmBtu with a weighted average contract cost of approximately $1.85 per mmBtu above market prices, compared to 134 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.56 per mmBtu above market prices and compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
                 
Asset (Liability) Derivatives   September 30, 2010   December 31, 2009
    (in millions)
Regulatory hedges
  $ (247 )   $ (175 )
Cash flow hedges
    1       (2 )
Not designated
    (3 )     (1 )
 
Total fair value
  $ (249 )   $ (178 )
 
Energy-related derivative contracts that are designated as regulatory hedges relate to the traditional operating companies’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in income for the three and nine months ended September 30, 2010 were $(4) million and $(2) million, respectively. For the three and nine months ended September 30, 2009, the total net unrealized pre-tax gains (losses) recognized in income were $2 million and $1 million, respectively.
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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010          
    Fair Value Measurements          
    Total     Maturity
    Fair Value     Year 1     Years 2&3     Years 4&5  
            (in millions)
Level 1
  $   —     $   —      $   —       $   —  
Level 2
    (249)        (168)       (80)           (1)  
Level 3
     —        —       —         —  
   
Fair value of contracts outstanding at end of period
  $(249)     $ (168)     $  (80)      $   (1)  
   
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 Note 1 under “Financial Instruments” and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the third quarter 2010, Southern Company issued approximately $198 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued approximately 2 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 approximately $73 million, net of $0.6 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the first nine months of 2010, Southern Company issued approximately $475 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued approximately 4 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 approximately $143 million, net of $1.2 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 March 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.
In April 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of its Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power’s continuous construction program.
In June 2010, Georgia Power issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of Georgia Power’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.
In June 2010, Gulf Power incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The net proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer.
In September 2010, Southern Company issued $400 million aggregate principal amount of Series 2010A 2.375% Senior Notes due September 15, 2015. The net proceeds will be used for the announced redemption of $250 million aggregate principal amount of Southern Company Capital Funding, Inc.’s Series C 5.75% Senior Notes due November 15, 2015 and were also used to repay a portion of its outstanding short-term indebtedness, and for other general corporate purposes.
In September 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay a portion of Mississippi Power’s short-term indebtedness and for general corporate purposes, including Mississippi Power’s continuous construction program.
In September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010C 4.75% Senior Notes due September 1, 2040. The net proceeds were used to redeem all of the $250 million aggregate principal amount of Georgia Power’s Series X 5.70% Senior Notes due January 15, 2045, $125 million aggregate principal amount of Georgia Power’s Series W 6% Senior Notes due August 15, 2044, $100 million aggregate principal amount of Georgia Power’s Series T 5.75% Senior Public Income Notes due January 15, 2044, and $35 million aggregate principal amount of Savannah Electric and Power Company’s (Savannah Electric) Series G 5.75% Senior Notes due December 1, 2044 (which were assumed by Georgia Power upon its merger with Savannah Electric).
Also in September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15, 2013. Subsequent to September 30, 2010, the net proceeds were used for the repurchase of all of the $114.3 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 2009, due January 1, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), First Series 2009, due January 1, 2049; $173 million aggregate principal

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
amount of the outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Plant Bowen Project), First Series 2009, due December 1, 2032; $89.2 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), Second Series 2009, due October 1, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 1996, due October 1, 2032, and for other general corporate purposes, including Georgia Power’s continuous construction program. The pollution control revenue bonds repurchased by Georgia Power are being held by Georgia Power and may be remarketed to investors in the future.
In September 2010, Gulf Power issued $125 million aggregate principal amount of its Series 2010B 5.10% Senior Notes due October 1, 2040. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power’s continuous construction program, and, subsequent to September 30, 2010, for the redemption of all of the $40 million aggregate principal amount of Gulf Power’s Series I 5.75% Senior Notes due September 15, 2033 and $35 million aggregate principal amount of Gulf Power’s Series J 5.875% Senior Notes due April 1, 2044.
Subsequent to September 30, 2010, Alabama Power issued $250 million aggregate principal amount of Series 2010A 3.375% Senior Notes due October 1, 2020. Subsequent to September 30, 2010, the net proceeds were used for the redemption of $150 million aggregate principal amount of Alabama Power’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including Alabama Power’s continuous construction program.
See Southern Company’s Condensed Consolidated Statements of Cash Flows herein for further details regarding financing activities during the first nine months of 2010.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for each registrant and Note 1 to the financial statements of each registrant under “Financial Instruments,” Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, and Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
     (a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this quarterly report, Southern Company 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.
There have been no changes in Southern Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting other than as described in the next paragraph.
In August 2010, Alabama Power implemented a new general ledger system and Mississippi Power implemented new general ledger, supply chain, and work management systems. These systems provide additional operational and internal control benefits including system security and the automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.
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.
There have been no changes in Georgia Power’s, Gulf Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Georgia Power’s, Gulf Power’s, or Southern Power’s internal control over financial reporting.
There have been no changes in Alabama Power’s and Mississippi Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Alabama Power’s and Mississippi Power’s internal control over financial reporting, other than as described in the next paragraph.

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In August 2010, Alabama Power implemented a new general ledger system and Mississippi Power implemented new general ledger, supply chain, and work management systems. These systems provide additional operational and internal control benefits including system security and the automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.

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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,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 1,526,738     $ 1,342,665     $ 3,924,612     $ 3,520,408  
Wholesale revenues, non-affiliates
    85,823       170,573       395,164       483,180  
Wholesale revenues, affiliates
    42,966       34,042       193,622       170,887  
Other revenues
    50,406       44,876       149,927       123,963  
 
                       
Total operating revenues
    1,705,933       1,592,156       4,663,325       4,298,438  
 
                       
Operating Expenses:
                               
Fuel
    500,150       506,376       1,455,226       1,437,095  
Purchased power, non-affiliates
    34,931       42,915       65,532       84,582  
Purchased power, affiliates
    57,524       73,966       161,216       172,096  
Other operations and maintenance
    378,133       272,118       997,731       827,275  
Depreciation and amortization
    153,488       136,784       451,065       406,687  
Taxes other than income taxes
    84,261       77,353       247,592       239,673  
 
                       
Total operating expenses
    1,208,487       1,109,512       3,378,362       3,167,408  
 
                       
Operating Income
    497,446       482,644       1,284,963       1,131,030  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    8,155       21,053       28,529       56,931  
Interest income
    4,129       4,419       12,143       12,689  
Interest expense, net of amounts capitalized
    (76,292 )     (75,817 )     (226,986 )     (224,792 )
Other income (expense), net
    (6,137 )     (6,714 )     (17,827 )     (17,577 )
 
                       
Total other income and (expense)
    (70,145 )     (57,059 )     (204,141 )     (172,749 )
 
                       
Earnings Before Income Taxes
    427,301       425,585       1,080,822       958,281  
Income taxes
    157,782       154,050       398,912       344,416  
 
                       
Net Income
    269,519       271,535       681,910       613,865  
Dividends on Preferred and Preference Stock
    9,866       9,866       29,598       29,598  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 259,653     $ 261,669     $ 652,312     $ 584,267  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 259,653     $ 261,669     $ 652,312     $ 584,267  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $18, $(187), $8, and $(1,773), respectively
    30       (307 )     13       (2,916 )
Reclassification adjustment for amounts included in net income, net of tax of $(68), $1,217, $475, and $3,456, respectively
    (110 )     2,002       782       5,685  
 
                       
Total other comprehensive income (loss)
    (80 )     1,695       795       2,769  
 
                       
Comprehensive Income
  $ 259,573     $ 263,364     $ 653,107     $ 587,036  
 
                       
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,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 681,910     $ 613,865  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    519,320       474,250  
Deferred income taxes
    301,119       (32,333 )
Allowance for equity funds used during construction
    (28,529 )     (56,931 )
Pension, postretirement, and other employee benefits
    (8,840 )     (2,955 )
Stock based compensation expense
    4,174       3,475  
Other, net
    27,933       25,302  
Changes in certain current assets and liabilities —
               
-Receivables
    (109,948 )     232,890  
-Fossil fuel stock
    21,130       (20,609 )
-Materials and supplies
    (9,906 )     (22,783 )
-Other current assets
    (33,540 )     (43,436 )
-Accounts payable
    (66,037 )     (197,357 )
-Accrued taxes
    (48,091 )     168,493  
-Accrued compensation
    7,541       (46,583 )
-Other current liabilities
    (103,390 )     70,111  
 
           
Net cash provided from operating activities
    1,154,846       1,165,399  
 
           
Investing Activities:
               
Property additions
    (684,738 )     (896,913 )
Distribution of restricted cash from pollution control revenue bonds
    18,464       39,866  
Nuclear decommissioning trust fund purchases
    (126,039 )     (177,639 )
Nuclear decommissioning trust fund sales
    126,039       177,639  
Cost of removal, net of salvage
    (25,830 )     (21,419 )
Change in construction payables
    (34,329 )     37,486  
Other investing activities
    (9,212 )     (27,484 )
 
           
Net cash used for investing activities
    (735,645 )     (868,464 )
 
           
Financing Activities:
               
Decrease in notes payable, net
          (24,995 )
Proceeds —
               
Common stock issued to parent
          135,000  
Capital contributions from parent company
    18,823       17,177  
Pollution control revenue bonds
          53,000  
Senior notes issuances
          500,000  
Redemptions —
               
Senior notes
          (250,000 )
Payment of preferred and preference stock dividends
    (29,670 )     (29,602 )
Payment of common stock dividends
    (407,025 )     (392,100 )
Other financing activities
    (1,242 )     (2,474 )
 
           
Net cash provided from (used for) financing activities
    (419,114 )     6,006  
 
           
Net Change in Cash and Cash Equivalents
    87       302,941  
Cash and Cash Equivalents at Beginning of Period
    368,016       28,181  
 
           
Cash and Cash Equivalents at End of Period
  $ 368,103     $ 331,122  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $11,121 and $23,813 capitalized for 2010 and 2009, respectively)
  $ 214,102     $ 190,014  
Income taxes (net of refunds)
  $ 212,036     $ 274,486  
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   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 368,103     $ 368,016  
Restricted cash and cash equivalents
    18,249       36,711  
Receivables —
               
Customer accounts receivable
    451,381       322,292  
Unbilled revenues
    142,372       134,875  
Under recovered regulatory clause revenues
    12,065       37,338  
Other accounts and notes receivable
    46,986       33,522  
Affiliated companies
    45,382       61,508  
Accumulated provision for uncollectible accounts
    (12,035 )     (9,551 )
Fossil fuel stock, at average cost
    369,074       394,511  
Materials and supplies, at average cost
    335,954       326,074  
Vacation pay
    54,038       53,607  
Prepaid expenses
    222,608       111,320  
Other regulatory assets, current
    45,246       34,347  
Other current assets
    8,633       6,203  
 
           
Total current assets
    2,108,056       1,910,773  
 
           
Property, Plant, and Equipment:
               
In service
    19,794,009       18,574,229  
Less accumulated provision for depreciation
    6,861,206       6,558,864  
 
           
Plant in service, net of depreciation
    12,932,803       12,015,365  
Nuclear fuel, at amortized cost
    296,484       253,308  
Construction work in progress
    560,185       1,256,311  
 
           
Total property, plant, and equipment
    13,789,472       13,524,984  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    61,600       59,628  
Nuclear decommissioning trusts, at fair value
    516,696       489,795  
Miscellaneous property and investments
    70,066       69,749  
 
           
Total other property and investments
    648,362       619,172  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    411,986       387,447  
Prepaid pension costs
    159,843       132,643  
Other regulatory assets, deferred
    741,280       750,492  
Other deferred charges and assets
    207,103       198,582  
 
           
Total deferred charges and other assets
    1,520,212       1,469,164  
 
           
Total Assets
  $ 18,066,102     $ 17,524,093  
 
           
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   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 450,000     $ 100,000  
Accounts payable —
               
Affiliated
    225,885       194,675  
Other
    193,220       328,400  
Customer deposits
    85,849       86,975  
Accrued taxes —
               
Accrued income taxes
    1,721       14,789  
Other accrued taxes
    101,088       31,918  
Accrued interest
    65,219       65,455  
Accrued vacation pay
    44,415       44,751  
Accrued compensation
    81,239       71,286  
Liabilities from risk management activities
    40,499       37,844  
Over recovered regulatory clause revenues
    95,227       181,565  
Other current liabilities
    38,062       40,020  
 
           
Total current liabilities
    1,422,424       1,197,678  
 
           
Long-term Debt
    5,732,575       6,082,489  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,572,558       2,293,468  
Deferred credits related to income taxes
    85,979       88,705  
Accumulated deferred investment tax credits
    158,770       164,713  
Employee benefit obligations
    405,342       387,936  
Asset retirement obligations
    511,828       491,007  
Other cost of removal obligations
    701,073       668,151  
Other regulatory liabilities, deferred
    198,742       169,224  
Deferred over recovered regulatory clause revenues
    5,495       22,060  
Other deferred credits and liabilities
    77,676       37,113  
 
           
Total deferred credits and other liabilities
    4,717,463       4,322,377  
 
           
Total Liabilities
    11,872,462       11,602,544  
 
           
Redeemable Preferred Stock
    341,715       341,715  
 
           
Preference Stock
    343,373       343,373  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $40 per share —
               
Authorized - 40,000,000 shares
               
Outstanding - 30,537,500 shares
    1,221,500       1,221,500  
Paid-in capital
    2,145,902       2,119,818  
Retained earnings
    2,145,738       1,900,526  
Accumulated other comprehensive loss
    (4,588 )     (5,383 )
 
           
Total common stockholder’s equity
    5,508,552       5,236,461  
 
           
Total Liabilities and Stockholder’s Equity
  $ 18,066,102     $ 17,524,093  
 
           
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 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
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 given current economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing 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 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.0)   (0.8)   $68.0   11.6
 
Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2010 was $259.7 million compared to $261.7 million for the corresponding period in 2009. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2010 was $652.3 million compared to $584.3 million for the corresponding period in 2009. For the third quarter 2010, the decrease in net income when compared to the corresponding period in 2009 was not material. The increase for year-to-date 2010 when compared to the corresponding period in 2009 was primarily due to increases in rates under Rate RSE and Rate CNP Environmental that took effect in January 2010, warmer weather in the second and third quarters 2010 as well as significantly colder weather in the first quarter 2010, and increases in industrial sales. The increases in revenues were partially offset by increases in operations and maintenance expenses, which include an additional NDR accrual in the third quarter 2010, and depreciation and amortization and a reduction in AFUDC equity.
The increases in rates under Rate RSE and Rate CNP Environmental were offset by decreases in Rate ECR and the costs associated with the expiration of a PPA certificated by the Alabama PSC, resulting in an overall annual reduction in Alabama Power’s retail customer billing rates in 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$184.0   13.7   $404.2   11.5
 
In the third quarter 2010, retail revenues were $1.53 billion compared to $1.34 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $3.92 billion compared to $3.52 billion for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 1,342.7             $ 3,520.4          
Estimated change in —
                               
Rates and pricing
    90.4       6.7       218.7       6.2  
Sales growth (decline)
    (1.6 )     (0.1 )     6.4       0.2  
Weather
    82.6       6.2       163.7       4.7  
Fuel and other cost recovery
    12.6       0.9       15.4       0.4  
 
Retail – current year
  $ 1,526.7       13.7 %   $ 3,924.6       11.5 %
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to Rate RSE and Rate CNP Environmental increases effective January 2010.
Revenues attributable to changes in sales decreased in the third quarter 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 8.8% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales decreased 2.5% driven by a decrease in demand. Weather-adjusted commercial KWH energy sales growth was not material.
Revenues attributable to changes in sales increased year-to-date 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 12.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales growth was not material. Weather-adjusted commercial KWH energy sales decreased 1.2% driven by a decline in the number of customers.
Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to increased generation. These increases were offset primarily by a decrease in costs associated with the expiration of a PPA certificated by the Alabama PSC and a reduction in the Rate NDR customer billing rate as a result of achieving the target reserve balance in January 2010. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(84.8)   (49.7)   $(88.0)   (18.2)
 
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. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $90.2 million and $107.4 million revenue reduction in the third quarter and year-to-date 2010, respectively. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.
In the third quarter 2010, wholesale revenues from non-affiliates were $85.8 million compared to $170.6 million for the corresponding period in 2009. This decrease was primarily due to a 62.3% decrease in KWH sales, partially offset by a 33.5% increase in the price of energy.
For year-to-date 2010, wholesale revenues from non-affiliates were $395.2 million compared to $483.2 million for the corresponding period in 2009. This decrease was primarily due to a 32.5% decrease in KWH sales, partially offset by a 21.1% increase in the price of energy.
Wholesale Revenues – Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$9.0   26.2   $22.7   13.3
 
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 2010, wholesale revenues from affiliates were $43.0 million compared to $34.0 million for the corresponding period in 2009. The increase was due to an 18.5% increase in prices and a 6.5% increase in KWH sales.
For year-to-date 2010, wholesale revenues from affiliates were $193.6 million compared to $170.9 million for the corresponding period in 2009. The increase was primarily due to an 8.7% increase in prices and a 4.3% 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 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$5.5   12.3   $26.0   20.9
 
In the third quarter 2010, other revenues were $50.4 million compared to $44.9 million for the corresponding period in 2009. This increase was due to a $3.7 million increase in transmission sales and a $3.2 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume, partially offset by a decrease in customer charges related to collection fees.
For year-to-date 2010, other revenues were $149.9 million compared to $124.0 million for the corresponding period in 2009. This increase was due to a $10.9 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume, an $8.2 million increase in transmission sales, a $1.3 million increase in customer charges related to reconnection fees, and a $1.3 million increase in pole attachment rentals.
Co-generation steam fuel revenues do not have a significant impact on earnings since they are generally offset by fuel expense.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Third Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ (6.2 )     (1.2 )   $ 18.1       1.3  
Purchased power – non-affiliates
    (8.0 )     (18.6 )     (19.0 )     (22.5 )
Purchased power – affiliates
    (16.5 )     (22.2 )     (10.9 )     (6.3 )
                         
Total fuel and purchased power expenses
  $ (30.7 )           $ (11.8 )        
                         
 
*   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 2010, total fuel and purchased power expenses were $592.6 million compared to $623.3 million for the corresponding period in 2009. The decrease was primarily due to a $41.3 million decrease in the volume of energy purchased, partially offset by a $14.9 million increase in KWHs generated.
For year-to-date 2010, the decrease in total fuel and purchased power expenses when compared to the corresponding period in 2009 was not material.
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   2010   2009   Change   2010   2009   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    2.72       2.80       (2.9 )     2.78       2.83       (1.8 )
Purchased power
    7.11       6.45       10.2       6.83       6.23       9.6  
 
In the third quarter 2010, the decrease in fuel expense when compared to the corresponding period in 2009 was not material. For year-to-date 2010, the increase in fuel expense when compared to the corresponding period in 2009 was not material.
Non-Affiliates
In the third quarter 2010, purchased power expense from non-affiliates was $34.9 million compared to $42.9 million for the corresponding period in 2009. This decrease was primarily related to a 35.8% decrease in the average cost per KWH purchased, partially offset by a 26.8% increase in the volume of energy purchased.
For year-to-date 2010, purchased power expense from non-affiliates was $65.5 million compared to $84.6 million for the corresponding period in 2009. This decrease was related to an 18.7% decrease in the volume of energy purchased and a 4.7% decrease in the average cost per KWH purchased.
Energy purchases from non-affiliates will vary depending on the market cost of available energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.
Affiliates
In the third quarter 2010, purchased power expense from affiliates was $57.5 million compared to $74.0 million for the corresponding period in 2009. The decrease was related to a 41.5% decrease in the amount of energy purchased, partially offset by a 33.0% increase in price.
For year-to-date 2010, purchased power expense from affiliates was $161.2 million compared to $172.1 million for the corresponding period in 2009. The decrease was related to a 27.2% increase in price, partially offset by a 26.3% decrease in the volume of energy purchased.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$106.0   39.0   $170.4   20.6
 
In the third quarter 2010, other operations and maintenance expenses were $378.1 million compared to $272.1 million for the corresponding period in 2009. Transmission and distribution expenses increased $58.8 million due primarily to an additional accrual of $40 million to the NDR. See FUTURE EARNINGS POTENTIAL – “FERC and Alabama PSC

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Matters – Retail Regulatory Matters” herein for additional information on the NDR. In addition, overhead line maintenance expenses increased. Steam production expenses increased $12.3 million due to environmental mandates (which are offset by revenues associated with Rate CNP Environmental) and maintenance costs related to increases in labor and materials expenses. Administrative and general expenses increased $20.6 million related to increases in the injuries and damages reserve, affiliated service companies’ expenses, and labor, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $8.2 million due to maintenance costs related to increases in labor.
For year-to-date 2010, other operations and maintenance expenses were $997.7 million compared to $827.3 million for the corresponding period in 2009. Transmission and distribution expenses increased $60.2 million due primarily to an additional accrual of $40 million to the NDR. See FUTURE EARNINGS POTENTIAL – “FERC and Alabama PSC Matters – Retail Regulatory Matters” herein for additional information on the NDR. In addition, overhead line maintenance expenses increased. Steam production expenses increased $48.4 million due to scheduled outage costs, environmental mandates (which are offset by revenues associated with Rate CNP Environmental), and maintenance costs related to increases in labor and materials expenses. Administrative and general expenses increased $43.3 million due to increases in the injuries and damages reserve, affiliated service companies’ expenses, labor, and property insurance expenses, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $12.2 million due to maintenance costs related to increases in labor.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$16.7   12.2   $44.4   10.9
 
In the third quarter 2010, depreciation and amortization was $153.5 million compared to $136.8 million for the corresponding period in 2009. For year-to-date 2010, depreciation and amortization was $451.1 million compared to $406.7 million for the corresponding period in 2009. These increases were due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.
Taxes Other Than Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$6.9   8.9   $7.9   3.3
 
In the third quarter 2010, taxes other than income taxes were $84.3 million compared to $77.4 million for the corresponding period in 2009. The increase was primarily due to increases in state and municipal public utility license tax bases.
For year-to-date 2010, the increase in taxes other than income taxes when compared to the corresponding period in 2009 was not material.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(12.9)   (61.3)   $(28.4)   (49.9)
 
In the third quarter 2010, AFUDC equity was $8.2 million compared to $21.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $28.5 million compared to $56.9 million for the corresponding period in 2009. These decreases were due to the completion of construction projects related to environmental mandates at generating facilities, partially offset by increases in nuclear facility projects.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$3.7   2.4   $54.5   15.8
 
In the third quarter 2010, the increase in total income taxes when compared to the corresponding period in 2009 was not material. For year-to-date 2010, income taxes were $398.9 million compared to $344.4 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings and a reduction of the tax benefits associated with a decrease in AFUDC equity.
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 all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Changes in economic conditions impact sales for Alabama Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
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.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
information regarding a civil action brought by the EPA alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.
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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO2) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO2, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Alabama Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and nitrogen oxides (NOx) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
These regulations could result in significant additional compliance and operational 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.
Coal Combustion Byproducts
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Alabama Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.
The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Alabama Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.
FERC and Alabama PSC Matters
Retail Regulatory Matters
Nuclear Outage Accounting Order
On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.
The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s over recovered fuel costs as of September 30, 2010 totaled $57.7 million as compared to $199.6 million at December 31, 2009. These over recovered fuel costs at September 30, 2010 are included in over recovered regulatory clause revenues and deferred over recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. The current and deferred classifications are based on estimates which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.
Natural Disaster Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery.
On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.
In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.
Hydro Relicensing
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters” of Alabama Power in Item 7 of the Form 10-K for information regarding Alabama Power’s applications to the FERC for new licenses for certain of its hydroelectric projects. On March 31, 2010, the FERC issued a new 30-year license for the Lewis Smith and Bankhead developments on the Warrior River. The new license authorizes Alabama Power to continue operating these facilities in a manner consistent with past operations. On April 30, 2010, a stakeholders group filed a request for rehearing of the FERC order issuing the new license. On May 27, 2010, the FERC granted the rehearing request for the limited purpose of allowing the FERC additional time to consider the substantive issues raised in the request. The ultimate outcome of this matter cannot be determined at this time.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Alabama Power in Item 7 of the Form 10-K for additional information.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Alabama Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Alabama Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Alabama Power cannot be determined at this time.
Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009 (ARRA). This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Alabama Power will receive, and will match, $65 million under this agreement.
On May 12, 2010, Alabama Power signed an agreement with the DOE formally accepting a $6 million grant under the ARRA. This funding will be used for hydro generation upgrades. The total upgrade project is expected to cost $30 million and Alabama Power plans to spend $24 million on the project.
Income Tax Matters
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $117 million for Alabama Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Alabama Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $102 million.
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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against 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.
The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Alabama Power’s service territory.
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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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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, 2010. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $1.16 billion for the first nine months of 2010, compared to $1.17 billion for the corresponding period in 2009. The $10.6 million decrease in cash provided from operating activities was primarily due to less cash collections of regulatory clause revenues when compared to the prior year, partially offset by an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $735.6 million in the first nine months of 2010 primarily due to gross property additions related to steam generation equipment and construction payables. Net cash used for financing activities totaled $419.1 million for the first nine months of 2010, compared to $6.0 million provided in the corresponding period in 2009. The $425.1 million decrease is primarily due to no issuances of securities in the first nine months of 2010. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2010 include increases of $264.5 million in total property, plant, and equipment related to environmental projects, partially offset by a reduction in construction work in progress and an increase in accumulated provision for depreciation; $129.1 million in customer accounts receivable; $111.3 million in prepaid expenses; $279.1 million in accumulated deferred income taxes; and $245.2 million in retained earnings.
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, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $450 million will be required through September 30, 2011 to fund maturities and announced redemptions of long-term debt. No mandatory contributions to Alabama Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of 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
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, 2010 cash and cash equivalents of approximately $368 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the cash and cash equivalents, approximately $319 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $60 million expire in 2010, $446 million expire in 2011, and $765 million expire in 2012. All of the credit arrangements that expire in 2010 contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama Power’s commercial paper borrowings and $798 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. 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, 2010, Alabama Power had no commercial paper borrowings outstanding. During the third quarter 2010, Alabama Power had an average of $8 million of commercial paper outstanding at a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $60 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $343 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.
On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of Alabama Power’s preferred stock, preference stock, and long-term debt payable to affiliated trusts decreased from A to A-. These ratings are not applicable to the collateral requirements described above.
Market Price Risk
Alabama Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 reporting period. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (45 )   $ (44 )
Contracts realized or settled
    14       48  
Current period changes(a)
    (23 )     (58 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (54 )   $ (54 )
 
(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2010 was a decrease of $9 million and a decrease of $10 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Alabama Power had a net hedge volume of 34 million mmBtu with a weighted average contract cost of approximately $1.62 per mmBtu above market prices, compared to 31 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.47 per mmBtu above market prices and 36 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.22 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clause.
Regulatory hedges relate to Alabama Power’s fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.
Alabama Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (54 )     (40 )     (14 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (54 )   $ (40 )   $ (14 )   $  
 
See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
Subsequent to September 30, 2010, Alabama Power issued $250 million aggregate principal amount of Series 2010A 3.375% Senior Notes due October 1, 2020. Subsequent to September 30, 2010, the net proceeds were used for the redemption of $150 million aggregate principal amount of Alabama Power’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including Alabama Power’s continuous construction program.
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,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 2,418,231     $ 2,093,503     $ 6,036,216     $ 5,368,123  
Wholesale revenues, non-affiliates
    108,938       108,521       307,167       301,077  
Wholesale revenues, affiliates
    16,844       53,687       43,118       98,520  
Other revenues
    84,163       71,477       225,345       199,623  
 
                       
Total operating revenues
    2,628,176       2,327,188       6,611,846       5,967,343  
 
                       
Operating Expenses:
                               
Fuel
    928,016       830,283       2,442,897       2,083,662  
Purchased power, non-affiliates
    128,557       86,450       294,098       219,220  
Purchased power, affiliates
    142,509       158,864       436,507       528,505  
Other operations and maintenance
    434,904       358,821       1,224,157       1,102,876  
Depreciation and amortization
    181,866       122,740       426,094       464,931  
Taxes other than income taxes
    98,732       86,620       264,372       243,876  
 
                       
Total operating expenses
    1,914,584       1,643,778       5,088,125       4,643,070  
 
                       
Operating Income
    713,592       683,410       1,523,721       1,324,273  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    34,039       23,200       104,694       66,267  
Interest income
    603       611       1,398       1,644  
Interest expense, net of amounts capitalized
    (94,596 )     (95,309 )     (274,918 )     (293,124 )
Other income (expense), net
    (5,754 )     (4,127 )     (12,967 )     (8,316 )
 
                       
Total other income and (expense)
    (65,708 )     (75,625 )     (181,793 )     (233,529 )
 
                       
Earnings Before Income Taxes
    647,884       607,785       1,341,928       1,090,744  
Income taxes
    223,669       215,720       432,851       378,030  
 
                       
Net Income
    424,215       392,065       909,077       712,714  
Dividends on Preferred and Preference Stock
    4,345       4,345       13,036       13,036  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 419,870     $ 387,720     $ 896,041     $ 699,678  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 419,870     $ 387,720     $ 896,041     $ 699,678  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $-, $(430), $(6), and $(156), respectively
          (682 )     (10 )     (247 )
Reclassification adjustment for amounts included in net income, net of tax of $1,379, $2,350, $5,136, and $6,520, respectively
    2,186       3,725       8,143       10,336  
 
                       
Total other comprehensive income (loss)
    2,186       3,043       8,133       10,089  
 
                       
Comprehensive Income
  $ 422,056     $ 390,763     $ 904,174     $ 709,767  
 
                       
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,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 909,077     $ 712,714  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    550,940       566,741  
Deferred income taxes
    225,432       111,035  
Deferred revenues
    (77,081 )     (37,210 )
Deferred expenses
    (53,761 )     (39,570 )
Allowance for equity funds used during construction
    (104,694 )     (66,267 )
Pension, postretirement, and other employee benefits
    20,458       16,713  
Hedge settlements
          (16,167 )
Insurance cash surrender value
    1,275       22,381  
Other, net
    (8,925 )     21,131  
Changes in certain current assets and liabilities —
               
-Receivables
    (125,658 )     3,648  
-Fossil fuel stock
    153,144       (245,777 )
-Prepaid income taxes
    2,096       (20,694 )
-Other current assets
    4,006       505  
-Accounts payable
    61,223       40,719  
-Accrued taxes
    65,873       131,432  
-Accrued compensation
    45,015       (105,097 )
-Other current liabilities
    38,103       35,575  
 
           
Net cash provided from operating activities
    1,706,523       1,131,812  
 
           
Investing Activities:
               
Property additions
    (1,628,055 )     (1,778,030 )
Distribution of restricted cash from pollution control revenue bonds
          22,077  
Nuclear decommissioning trust fund purchases
    (569,815 )     (889,049 )
Nuclear decommissioning trust fund sales
    545,561       841,763  
Nuclear decommissioning trust securities lending collateral
    20,793       43,824  
Cost of removal, net of salvage
    (45,918 )     (41,709 )
Change in construction payables, net of joint owner portion
    27,345       45,828  
Other investing activities
    (16,318 )     7,519  
 
           
Net cash used for investing activities
    (1,666,407 )     (1,747,777 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (320,549 )     (103,634 )
Proceeds —
               
Capital contributions from parent company
    681,353       923,840  
Pollution control revenue bonds issuances
          416,510  
Senior notes issuances
    1,950,000       500,000  
Other long-term debt issuances
          1,100  
Redemptions —
               
Pollution control revenue bonds
          (327,310 )
Senior notes
    (1,111,914 )     (332,841 )
Other long-term debt
    (2,500 )      
Payment of preferred and preference stock dividends
    (13,300 )     (13,121 )
Payment of common stock dividends
    (615,000 )     (554,175 )
Other financing activities
    (32,761 )     (12,674 )
 
           
Net cash provided from financing activities
    535,329       497,695  
 
           
Net Change in Cash and Cash Equivalents
    575,445       (118,270 )
Cash and Cash Equivalents at Beginning of Period
    14,309       132,739  
 
           
Cash and Cash Equivalents at End of Period
  $ 589,754     $ 14,469  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $39,022 and $28,443 capitalized for 2010 and 2009, respectively)
  $ 231,285     $ 239,290  
Income taxes (net of refunds)
  $ 107,427     $ 115,436  
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   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 589,754     $ 14,309  
Receivables —
               
Customer accounts receivable
    753,688       486,885  
Unbilled revenues
    206,150       172,035  
Under recovered regulatory clause revenues
    196,149       291,837  
Joint owner accounts receivable
    45,288       146,932  
Other accounts and notes receivable
    55,466       62,758  
Affiliated companies
    28,593       11,775  
Accumulated provision for uncollectible accounts
    (13,309 )     (9,856 )
Fossil fuel stock, at average cost
    573,122       726,266  
Materials and supplies, at average cost
    367,308       362,803  
Vacation pay
    73,806       74,566  
Prepaid income taxes
    90,058       132,668  
Other regulatory assets, current
    105,665       76,634  
Other current assets
    117,249       62,651  
 
           
Total current assets
    3,188,987       2,612,263  
 
           
Property, Plant, and Equipment:
               
In service
    26,109,530       25,120,034  
Less accumulated provision for depreciation
    9,857,869       9,493,068  
 
           
Plant in service, net of depreciation
    16,251,661       15,626,966  
Nuclear fuel, at amortized cost
    364,372       339,810  
Construction work in progress
    3,079,691       2,521,091  
 
           
Total property, plant, and equipment
    19,695,724       18,487,867  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    68,037       66,106  
Nuclear decommissioning trusts, at fair value
    625,869       580,322  
Miscellaneous property and investments
    38,391       38,516  
 
           
Total other property and investments
    732,297       684,944  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    707,496       608,851  
Deferred under recovered regulatory clause revenues
    291,736       373,245  
Other regulatory assets, deferred
    1,331,659       1,321,904  
Other deferred charges and assets
    202,049       205,492  
 
           
Total deferred charges and other assets
    2,532,940       2,509,492  
 
           
Total Assets
  $ 26,149,948     $ 24,294,566  
 
           
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   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 874,817     $ 253,882  
Notes payable
    3,410       323,958  
Accounts payable —
               
Affiliated
    293,416       238,599  
Other
    545,539       602,003  
Customer deposits
    200,189       200,103  
Accrued taxes —
               
Accrued income taxes
    79,533       548  
Unrecognized tax benefits
    177,241       164,863  
Other accrued taxes
    261,155       290,174  
Accrued interest
    117,228       89,228  
Accrued vacation pay
    55,098       57,662  
Accrued compensation
    91,663       42,756  
Liabilities from risk management activities
    84,146       49,788  
Other cost of removal obligations, current
    37,000       216,000  
Other regulatory liabilities, current
    21,066       99,807  
Other current liabilities
    117,382       84,319  
 
           
Total current liabilities
    2,958,883       2,713,690  
 
           
Long-term Debt
    7,985,180       7,782,340  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    3,648,873       3,389,907  
Deferred credits related to income taxes
    129,985       133,683  
Accumulated deferred investment tax credits
    232,566       242,496  
Employee benefit obligations
    945,999       923,177  
Asset retirement obligations
    703,827       676,705  
Other cost of removal obligations
    186,793       124,662  
Other deferred credits and liabilities
    210,345       139,024  
 
           
Total deferred credits and other liabilities
    6,058,388       5,629,654  
 
           
Total Liabilities
    17,002,451       16,125,684  
 
           
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
    5,281,791       4,592,350  
Retained earnings
    3,213,975       2,932,934  
Accumulated other comprehensive loss
    (12,699 )     (20,832 )
 
           
Total common stockholder’s equity
    8,881,540       7,902,925  
 
           
Total Liabilities and Stockholder’s Equity
  $ 26,149,948     $ 24,294,566  
 
           
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 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power filed a general rate case on July 1, 2010, requesting a base rate increase effective January 1, 2011. On March 11, 2010, the Georgia PSC approved Georgia Power’s request to increase its fuel cost recovery rate effective April 1, 2010. Georgia Power is required to file its next fuel cost recovery case by March 1, 2011.
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 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$32.2   8.3   $196.3   28.1
       
Georgia Power’s net income after dividends on preferred and preference stock for the third quarter 2010 was $419.9 million compared to $387.7 million for the corresponding period in 2009. The increase was due primarily to higher residential base revenues resulting from warmer weather in the third quarter 2010, partially offset by a reduction in the amortization of the regulatory liability related to other cost of removal obligations that began in July 2009 as authorized by the Georgia PSC, as well as higher operations and maintenance expenses.
Georgia Power’s year-to-date 2010 net income after dividends on preferred and preference stock was $896.0 million compared to $699.7 million for the corresponding period in 2009. The increase was due primarily to higher residential base revenues resulting from warmer weather in the second and third quarters 2010, significantly colder weather in the first quarter 2010, and the amortization of the regulatory liability related to other cost of removal obligations, partially offset by increases in operations and maintenance expenses.
Retail Revenues
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$324.7   15.5   $668.1   12.4
       
In the third quarter 2010, retail revenues were $2.4 billion compared to $2.1 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $6.0 billion compared to $5.4 billion for the corresponding period in 2009.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 2,093.5             $ 5,368.1          
Estimated change in —
                               
Rates and pricing
    49.5       2.4       21.8       0.4  
Sales growth (decline)
    9.8       0.4       49.9       0.9  
Weather
    104.3       5.0       181.9       3.4  
Fuel cost recovery
    161.1       7.7       414.5       7.7  
 
Retail – current year
  $ 2,418.2       15.5 %   $ 6,036.2       12.4 %
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 due to higher contributions from market-driven rates for sales to industrial customers and increased recognition of environmental compliance cost recovery revenues in accordance with the 2007 Retail Rate Plan.
Revenues attributable to changes in sales increased for all customer classes in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009. Weather-adjusted KWH energy sales increased 2.0%, decreased 1.8%, and increased 4.3% in the third quarter 2010 when compared to the corresponding period in 2009 for residential, commercial, and industrial classes, respectively. Weather-adjusted KWH energy sales increased 1.7%, decreased 0.4%, and increased 6.3% for year-to-date 2010 when compared to the corresponding period in 2009 for residential, commercial, and industrial classes, respectively.
Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $161.1 million in the third quarter 2010 and $414.5 million for year-to-date 2010 when compared to the corresponding periods in 2009 due to increased KWH energy sales and higher fuel costs. See Note (B) to the Condensed Financial Statements under “State PSC Matters – Georgia Power – Fuel Cost Recovery” herein for additional information.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.
Wholesale Revenues – Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$(36.8)   (68.6)   $(55.4)   (56.2)
       
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2010, wholesale revenues from affiliates were $16.9 million compared to $53.7 million for the corresponding period in 2009. For year-to-date 2010, wholesale revenues from affiliates were $43.1 million compared to $98.5 million for the corresponding period in 2009. These decreases were due to an 80.6% decrease and a 63.6% decrease in KWH sales due to lower demand in the third quarter and year-to-date 2010, respectively, because the market cost of available energy was lower than the cost of Georgia Power-owned generation.
Other Revenues
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$12.7   17.7   $25.7   12.9
       
In the third quarter 2010, other revenues were $84.2 million compared to $71.5 million for the corresponding period in 2009. This increase was primarily due to a $10.4 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies and an increase of $0.9 million in outdoor lighting revenues.
For year-to-date 2010, other revenues were $225.3 million compared to $199.6 million for the corresponding period in 2009. This increase was due to a $16.7 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies, a $5.1 million increase in late payment fees and customer maintenance request revenues, an increase of $2.0 million in pole attachment and equipment rental revenue primarily as a result of a new transmission line rental agreement that began in June 2009, and an increase of $2.3 million in outdoor lighting revenues primarily as a result of new customer sales associated with government stimulus programs.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Third Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ 97.7       11.8     $ 359.2       17.2  
Purchased power – non-affiliates
    42.1       48.7       74.9       34.2  
Purchased power – affiliates
    (16.4 )     (10.3 )     (92.0 )     (17.4 )
                       
Total fuel and purchased power expenses
  $ 123.4             $ 342.1          
                       
*   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 2010, total fuel and purchased power expenses were $1.2 billion compared to $1.1 billion in the corresponding period in 2009. This increase was primarily due to an $87.7 million increase related to higher KWHs generated primarily due to higher customer demand as a result of warmer weather in the third quarter 2010 and a $35.7 million increase in the average cost of fuel and purchased power.
For year-to-date 2010, total fuel and purchased power expenses were $3.2 billion compared to $2.8 billion in the corresponding period in 2009. This increase was due to a $218.4 million increase in the average cost of fossil and nuclear fuel and a $123.7 million increase related to higher KWHs generated primarily due to higher customer demand as a result of significantly colder weather in the first quarter 2010 and warmer weather in the second and third quarters 2010.
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 – “Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter   Percent   Year-to-Date   Year-to-Date   Percent
Average Cost   2010   2009   Change   2010   2009   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    3.97       3.50       13.4       3.84       3.39       13.3  
Purchased power
    5.50       6.43       (14.5 )     5.90       6.14       (3.9 )
 
In the third quarter 2010, fuel expense was $928.0 million compared to $830.3 million in the corresponding period in 2009. This increase was due to a 13.4% increase in the average cost of fuel per KWH and a 1.4% increase of KWHs generated as a result of higher KWH demand. The average cost of coal and natural gas increased 8.1% and 44.6%, respectively.
For year-to-date 2010, fuel expense was $2.4 billion compared to $2.1 billion in the corresponding period in 2009. This increase was due to a 13.3% increase in the average cost of fuel per KWH and a 6.6% increase of KWHs generated as a result of higher KWH demand. The average cost of coal and natural gas increased 9.3% and 32.8%, respectively.
Non-Affiliates
In the third quarter 2010, purchased power expense from non-affiliates was $128.6 million compared to $86.5 million in the corresponding period in 2009. This increase was due to a 13.6% increase in the average cost per KWH purchased reflecting higher fuel costs and a 49.3% increase in the volume of KWHs purchased due to higher KWH demand as a result of warmer weather in the third quarter 2010 as compared to the corresponding period in 2009.
For year-to-date 2010, purchased power expense from non-affiliates was $294.1 million compared to $219.2 million in the corresponding period in 2009. This increase was due to a 29.4% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, higher fuel costs, and a 14.3% increase in the volume of KWHs purchased due to higher KWH demand as a result of significantly colder weather in the first quarter 2010 and warmer weather in the second and third quarters 2010 as compared to the corresponding periods in 2009.
Energy purchases from non-affiliates will vary depending on the market cost of available energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.
Affiliates
In the third quarter 2010, purchased power expense from affiliates was $142.5 million compared to $158.9 million in the corresponding period in 2009. This decrease was due to a 26.9% decrease in the average cost per KWH purchased following the expiration of a PPA in December 2009, partially offset by a 13.8% increase in the volume of KWHs purchased due to higher KWH demand.
For year-to-date 2010, purchased power expense from affiliates was $436.5 million compared to $528.5 million in the corresponding period in 2009. This decrease was due to a 15.1% decrease in the average cost per KWH purchased and a 3.8% decrease in the volume of KWHs purchased following the expiration of a PPA in December 2009.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$76.1   21.2   $121.3   11.0
       
In the third quarter 2010, other operations and maintenance expenses were $434.9 million compared to $358.8 million in the corresponding period in 2009. This increase was due to increases of $34.2 million in power generation, $19.0 million in transmission and distribution, $14.8 million in administrative and general expenses, and $8.5 million in customer accounting, service, and sales primarily due to cost containment efforts in 2009 as a result of economic conditions and higher generation levels to meet increased customer demand in 2010.
For year-to-date 2010, other operations and maintenance expenses were $1.2 billion compared to $1.1 billion in the corresponding period in 2009. This increase was due to increases of $80.0 million in power generation and $39.1 million in transmission and distribution due to cost containment efforts in 2009 as a result of economic conditions and higher generation levels to meet increased customer demand in 2010.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$59.1   48.2   $(38.8)   (8.4)
       
In the third quarter 2010, depreciation and amortization was $181.8 million compared to $122.7 million in the corresponding period in 2009. This increase was due to the amortization of $5.0 million in the third quarter 2010 compared to $54.0 million for the corresponding period in 2009 of the regulatory liability related to the other cost of removal obligations as authorized by the Georgia PSC and depreciation on additional plant in service related to transmission, distribution, and environmental projects.
For year-to-date 2010, depreciation and amortization was $426.1 million compared to $464.9 million in the corresponding period in 2009. This decrease was due to the amortization of $119.3 million for year-to-date 2010 compared to $54.0 million for the corresponding period in 2009 of the regulatory liability related to the other cost of removal obligations, as authorized by the Georgia PSC, partially offset by depreciation on additional plant in service related to transmission, distribution, and environmental projects.
See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – Rate Plans” herein for additional information on the amortization of the other cost of removal regulatory liability, which became effective in July 2009.
Taxes Other Than Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$12.1   14.0   $20.5   8.4
       
In the third quarter 2010, taxes other than income taxes were $98.7 million compared to $86.6 million in the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $264.4 million compared to $243.9 million in the corresponding period in 2009. These increases were due to higher municipal franchise fees resulting from increased retail revenues in the third quarter and year-to-date 2010.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$10.8   46.7   $38.4   58.0
       
In the third quarter 2010, AFUDC equity was $34.0 million compared to $23.2 million in the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $104.7 million compared to $66.3 million in the corresponding period in 2009. These increases were due to the increase in construction related to three new combined cycle units at Plant McDonough, two new nuclear generating units at Plant Vogtle, and ongoing environmental and transmission projects.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$7.9   3.7   $54.8   14.5
       
In the third quarter 2010, income taxes were $223.6 million compared to $215.7 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by the intra-period tax allocation impact, which maintains an effective tax rate each quarter consistent with the estimated annual effective tax rate. The estimated annual effective tax rate declined from 2009 to 2010 primarily as a result of increased state investment tax credits.
For year-to-date 2010, income taxes were $432.8 million compared to $378.0 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by a decrease in uncertain tax positions related to state income tax credits that remain subject to litigation and an increase in non-taxable AFUDC equity and state investment tax credits.
See FUTURE EARNINGS POTENTIAL – “Income Tax Matters” herein and Notes 3 and 5 to the financial statements of Georgia Power under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements under “Income Tax Matters – Georgia State Income Tax Credits” herein, and Note (G) to the Condensed Financial Statements under “Effective Tax Rate” and “Unrecognized Tax Benefits” herein for additional information.
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 all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA alleging that Georgia Power and Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of their coal-fired generating facilities. The action against Georgia Power has been administratively closed since 2001, and the case has not been reopened. Georgia Power is not a party to the case involving Alabama Power. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims in the case against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.
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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time.
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 information regarding proposed sulfur dioxide (SO2) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO2, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Georgia Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and nitrogen oxides (NOx) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Georgia, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Georgia, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
These regulations could result in significant additional compliance and operational 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.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Coal Combustion Byproducts
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Georgia Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.
The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Georgia Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia PSC Matters
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 information regarding Georgia Power’s fuel cost recovery. As of September 30, 2010, Georgia Power had a total under recovered fuel cost balance of approximately $488 million compared to $665 million at December 31, 2009. 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.
On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.
Rate Plans
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Rate Plans” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information.
On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.
In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1, 2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.
Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
  §   Continuation of a plus or minus 100 basis point range for ROE.
 
  §   Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
 
      The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.
 
  §   Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
 
  §   Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
 
  §   Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.
These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.
Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.
The final outcome of these matters cannot now be determined.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Georgia Power in Item 7 of the Form 10-K for additional information.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Georgia Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Georgia Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Georgia Power cannot be determined at this time.
Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Georgia Power will receive, and will match, $51 million under this agreement.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Georgia Power’s cash flow. See Note 5 to the financial statements of Georgia Power under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $110 million for Georgia Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Georgia Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $130 million.
Construction
Nuclear
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 of the Form 10-K for information regarding construction of two additional nuclear generating units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4).
In June 2009, the Southern Alliance for Clean Energy (SACE) 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 Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. The dismissal of the claim related to the Georgia Nuclear Energy Financing Act is subject to appeal and the plaintiffs are expected to re-file this claim in the future. In addition, on May 5, 2010, the court issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, the SACE and the Fulton County Taxpayers Foundation, Inc. filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The SACE subsequently appealed to the Superior Court of Fulton County.
In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors in response to 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.
On August 17, 2010, the Georgia PSC voted to approve Georgia Power’s semi-annual construction monitoring report including all construction and capital costs of $583 million made on Plant Vogtle Units 3 and 4 through December 31,

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2009. The Georgia PSC also approved an amendment to the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 that replaced certain index-based adjustments with fixed escalation factors. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4, effective January 1, 2011.
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 be determined at this time.
Other
In August 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. In September 2009, Georgia Power amended the report. As amended, the report included a request for an increase in the certified costs to construct Plant McDonough. On February 24, 2010, Georgia Power reached a stipulation agreement with the Georgia PSC staff that was approved by the Georgia PSC on March 16, 2010. The stipulation resolved the June 30, 2009 construction monitoring report, including the approval of actual expenditures and the requested increase in the certified amount.
On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. In addition, on September 7, 2010, the Georgia PSC approved the March 31, 2010 construction monitoring report including actual project expenditures incurred through March 31, 2010.
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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the 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.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Georgia Power’s financial condition remained stable at September 30, 2010. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $1.7 billion for the first nine months of 2010, compared to $1.1 billion for the corresponding period in 2009. The $574.7 million increase in cash provided from operating activities in the first nine months of 2010 is primarily due to a $196.3 million increase in net income, fuel inventory reductions in 2010, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $1.7 billion for the first nine months of 2010 and 2009 primarily due to gross property additions to utility plant. Net cash provided from financing activities totaled $535.3 million for the first nine months of 2010, compared to $497.7 million for the corresponding period in 2009. The $37.6 million increase is primarily due to higher issuance of long-term debt in 2010 partially offset by higher common stock dividends in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first nine months of 2010 include an increase of $1.2 billion in total property, plant, and equipment and an increase in paid in capital of $689.4 million reflecting equity contributions from Southern Company.
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, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $874.8 million will be required through September 30, 2011 to fund maturities and announced repurchases of long-term debt. Georgia Power met its obligations to repurchase $462.5 million in pollution control revenue bonds subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Georgia Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; 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 prevailing market conditions, regulatory approval, 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.
On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.
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, 2010 cash and cash equivalents of approximately $589.8 million and unused committed credit arrangements with banks of approximately $1.7 billion. Of the cash and cash equivalents, approximately $574 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $595 million expire in 2011 and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2011, $40 million contain provisions allowing two-year term loans executable at expiration and $220 million contain provisions allowing one-year term loans executable at expiration. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Georgia Power’s commercial paper program at September 30, 2010, and approximately $901 million was dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to September 30, 2010, purchase obligations related to variable rate pollution control revenue bonds outstanding were reduced to $438 million as described under “Financing Activities” herein. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At September 30, 2010, Georgia Power had no commercial paper outstanding. During the third quarter 2010, Georgia Power had an average of $120 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $283 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.4 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.
On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of Georgia Power’s preferred stock, preference stock, and long-term debt payable to affiliated trusts decreased from A to A-. These ratings are not applicable to the collateral requirements described above.
On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Georgia Power (senior unsecured to A3 from A2). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Georgia Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Georgia Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Georgia Power (to Baa2 from Baa1). Moody’s also downgraded the trust preferred securities rating of Georgia Power to Baa1 from A3. Moody’s announced that the ratings outlook for Georgia Power is stable.
Market Price Risk
Georgia Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (93 )   $ (75 )
Contracts realized or settled
    19       69  
Current period changes(a)
    (47 )     (115 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (121 )   $ (121 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $28 million and a decrease of $46 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Georgia Power had a net hedge volume of 61 million mmBtu with a weighted average contract cost of approximately $1.99 per mmBtu above market prices, compared to 67 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.40 per mmBtu above market prices and compared to 65 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.16 per mmBtu above market prices. The natural gas hedges are recovered through the fuel cost recovery mechanism.
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 the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.
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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (121 )     (84 )     (37 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (121 )   $ (84 )   $ (37 )   $  
 
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 Note 1 under “Financial Instruments” and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In March 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.
In June 2010, Georgia Power issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of Georgia Power’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.
In September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010C 4.75% Senior Notes due September 1, 2040. The net proceeds were used to redeem all of the $250 million aggregate principal amount of Georgia Power’s Series X 5.70% Senior Notes due January 15, 2045, $125 million aggregate principal amount of Georgia Power’s Series W 6% Senior Notes due August 15, 2044, $100 million aggregate principal amount of Georgia Power’s Series T 5.75% Senior Public Income Notes due January 15, 2044, and $35 million aggregate principal amount of Savannah Electric and Power Company’s (Savannah Electric) Series G 5.75% Senior Notes due December 1, 2044 (which were assumed by Georgia Power upon its merger with Savannah Electric).
Also in September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15, 2013. Subsequent to September 30, 2010, the net proceeds were used for the repurchase of all of the $114.3 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 2009, due January 1, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), First Series 2009, due January 1, 2049; $173 million aggregate principal amount of the outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Plant Bowen Project), First Series 2009, due December 1, 2032; $89.2 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), Second Series 2009, due October 1, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 1996, due October 1, 2032, and for other general corporate purposes, including Georgia Power’s continuous construction program. The pollution control revenue bonds repurchased by Georgia Power are being held by Georgia Power and may be remarketed to investors in the future.
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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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 396,671     $ 329,597     $ 1,021,530     $ 858,038  
Wholesale revenues, non-affiliates
    31,211       25,752       86,041       70,418  
Wholesale revenues, affiliates
    37,995       3,661       88,386       19,748  
Other revenues
    17,578       18,631       47,381       54,816  
 
                       
Total operating revenues
    483,455       377,641       1,243,338       1,003,020  
 
                       
Operating Expenses:
                               
Fuel
    237,003       163,302       585,167       435,050  
Purchased power, non-affiliates
    12,771       9,991       34,615       20,480  
Purchased power, affiliates
    20,282       29,399       51,725       58,020  
Other operations and maintenance
    67,178       57,422       202,202       194,896  
Depreciation and amortization
    34,032       23,452       90,651       69,828  
Taxes other than income taxes
    29,293       26,683       78,586       72,120  
 
                       
Total operating expenses
    400,559       310,249       1,042,946       850,394  
 
                       
Operating Income
    82,896       67,392       200,392       152,626  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    1,424       6,810       4,504       17,335  
Interest income
    31       129       87       423  
Interest expense, net of amounts capitalized
    (13,764 )     (9,264 )     (38,286 )     (29,003 )
Other income (expense), net
    (471 )     (266 )     (1,355 )     (1,369 )
 
                       
Total other income and (expense)
    (12,780 )     (2,591 )     (35,050 )     (12,614 )
 
                       
Earnings Before Income Taxes
    70,116       64,801       165,342       140,012  
Income taxes
    25,658       22,042       60,166       45,341  
 
                       
Net Income
    44,458       42,759       105,176       94,671  
Dividends on Preference Stock
    1,551       1,551       4,652       4,652  
 
                       
Net Income After Dividends on Preference Stock
  $ 42,907     $ 41,208     $ 100,524     $ 90,019  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                                
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preference Stock
  $ 42,907     $ 41,208     $ 100,524     $ 90,019  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $-, $(414), $(542), and $(414), respectively
          (659 )     (863 )     (659 )
Reclassification adjustment for amounts included in net income, net of tax of $90, $105, $286, and $314, respectively
    143       166       455       500  
 
                       
Total other comprehensive income (loss)
    143       (493 )     (408 )     (159 )
 
                       
Comprehensive Income
  $ 43,050     $ 40,715     $ 100,116     $ 89,860  
 
                       
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,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 105,176     $ 94,671  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    95,491       74,407  
Deferred income taxes
    55,355       (2,177 )
Allowance for equity funds used during construction
    (4,504 )     (17,335 )
Pension, postretirement, and other employee benefits
    2,883       1,123  
Stock based compensation expense
    959       793  
Hedge settlements
    1,530        
Other, net
    1,040       (4,009 )
Changes in certain current assets and liabilities —
               
-Receivables
    (67,814 )     40,388  
-Fossil fuel stock
    29,483       (54,511 )
-Materials and supplies
    (1,363 )     (1,411 )
-Prepaid income taxes
    (9,558 )     416  
-Property damage cost recovery
    34       10,831  
-Other current assets
    2,667       2,178  
-Accounts payable
    12,003       (13,022 )
-Accrued taxes
    18,166       14,593  
-Accrued compensation
    2,695       (7,364 )
-Other current liabilities
    10,776       8,627  
 
           
Net cash provided from operating activities
    255,019       148,198  
 
           
Investing Activities:
               
Property additions
    (203,911 )     (330,776 )
Investment in restricted cash from pollution control revenue bonds
          (49,188 )
Distribution of restricted cash from pollution control revenue bonds
    6,347       28,144  
Cost of removal, net of salvage
    (750 )     (6,758 )
Construction payables
    (17,792 )     (11,721 )
Payments pursuant to long-term service agreements
    (4,211 )     (5,462 )
Other investing activities
    (295 )     17  
 
           
Net cash used for investing activities
    (220,612 )     (375,744 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (88,733 )     (101,589 )
Proceeds —
               
Common stock issued to parent
    50,000       135,000  
Capital contributions from parent company
    3,571       3,461  
Pollution control revenue bonds
    21,000       130,400  
Senior notes
    300,000       140,000  
Redemptions —
               
Senior notes
    (140,413 )     (1,033 )
Payment of preference stock dividends
    (4,652 )     (4,652 )
Payment of common stock dividends
    (78,225 )     (66,975 )
Other financing activities
    (3,280 )     (1,613 )
 
           
Net cash provided from financing activities
    59,268       232,999  
 
           
Net Change in Cash and Cash Equivalents
    93,675       5,453  
Cash and Cash Equivalents at Beginning of Period
    8,677       3,443  
 
           
Cash and Cash Equivalents at End of Period
  $ 102,352     $ 8,896  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $1,795 and $6,909 capitalized for 2010 and 2009, respectively)
  $ 28,394     $ 29,123  
Income taxes (net of refunds)
  $ 13,862     $ 43,423  
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   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 102,352     $ 8,677  
Restricted cash and cash equivalents
          6,347  
Receivables —
               
Customer accounts receivable
    98,295       64,257  
Unbilled revenues
    64,894       60,414  
Under recovered regulatory clause revenues
    18,606       4,285  
Other accounts and notes receivable
    7,748       4,107  
Affiliated companies
    17,832       7,503  
Accumulated provision for uncollectible accounts
    (2,226 )     (1,913 )
Fossil fuel stock, at average cost
    153,230       183,619  
Materials and supplies, at average cost
    40,049       38,478  
Other regulatory assets, current
    23,560       19,172  
Prepaid expenses
    29,874       44,760  
Other current assets
    927       3,634  
 
           
Total current assets
    555,141       443,340  
 
           
Property, Plant, and Equipment:
               
In service
    3,552,116       3,430,503  
Less accumulated provision for depreciation
    1,052,758       1,009,807  
 
           
Plant in service, net of depreciation
    2,499,358       2,420,696  
Construction work in progress
    227,643       159,499  
 
           
Total property, plant, and equipment
    2,727,001       2,580,195  
 
           
Other Property and Investments
    16,219       15,923  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    44,947       39,018  
Other regulatory assets, deferred
    221,691       190,971  
Other deferred charges and assets
    31,940       24,160  
 
           
Total deferred charges and other assets
    298,578       254,149  
 
           
Total Assets
  $ 3,596,939     $ 3,293,607  
 
           
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   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 185,000     $ 140,000  
Notes payable
          90,331  
Accounts payable —
               
Affiliated
    59,361       47,421  
Other
    66,993       80,184  
Customer deposits
    35,695       32,361  
Accrued taxes —
               
Accrued income taxes
    2,816       1,955  
Other accrued taxes
    25,319       7,297  
Accrued interest
    14,959       10,222  
Accrued compensation
    12,032       9,337  
Other regulatory liabilities, current
    31,597       22,416  
Liabilities from risk management activities
    12,807       9,442  
Other current liabilities
    21,335       20,092  
 
           
Total current liabilities
    467,914       471,058  
 
           
Long-term Debt
    1,112,478       978,914  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    353,886       297,405  
Accumulated deferred investment tax credits
    8,495       9,652  
Employee benefit obligations
    110,708       109,271  
Other cost of removal obligations
    199,154       191,248  
Other regulatory liabilities, deferred
    42,481       41,399  
Other deferred credits and liabilities
    122,754       92,370  
 
           
Total deferred credits and other liabilities
    837,478       741,345  
 
           
Total Liabilities
    2,417,870       2,191,317  
 
           
Preference Stock
    97,998       97,998  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - September 30, 2010: 3,642,717 shares
               
- December 31, 2009: 3,142,717 shares
    303,060       253,060  
Paid-in capital
    539,466       534,577  
Retained earnings
    241,415       219,117  
Accumulated other comprehensive loss
    (2,870 )     (2,462 )
 
           
Total common stockholder’s equity
    1,081,071       1,004,292  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,596,939     $ 3,293,607  
 
           
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 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. 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 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$1.7
  4.1   $10.5   11.7
 
Gulf Power’s net income after dividends on preference stock for the third quarter 2010 was $42.9 million compared to $41.2 million for the corresponding period in 2009. The increase was primarily due to warmer weather in the third quarter 2010.
Gulf Power’s net income after dividends on preference stock for year-to-date 2010 was $100.5 million compared to $90.0 million for the corresponding period in 2009. The increase was primarily due to significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010.
Retail Revenues
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$67.1   20.4   $163.5   19.1
 
In the third quarter 2010, retail revenues were $396.7 million compared to $329.6 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $1,021.5 million compared to $858.0 million for the corresponding period in 2009.

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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
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 329.6             $ 858.0          
Estimated change in –
                               
Rates and pricing
    22.2       6.7       56.0       6.5  
Sales growth (decline)
    0.8       0.3       (2.8 )     (0.2 )
Weather
    6.5       2.0       18.3       2.1  
Fuel and other cost recovery
    37.6       11.4       92.0       10.7  
 
Retail – current year
  $ 396.7       20.4     $ 1,021.5       19.1  
 
Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to revenues associated with higher projected environmental compliance costs in 2010.
Annually, Gulf Power petitions the Florida PSC for recovery of projected environmental compliance costs including any true-up amounts from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the third quarter 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers increased 5.2% primarily due to an increase in production for one large customer. Weather-adjusted KWH energy sales to commercial customers increased 3.0% primarily due to increased sales to certain large customers. Weather-adjusted KWH energy sales to residential customers remained flat.
Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. The decrease was primarily due to a decrease in KWH usage in the residential class. KWH energy sales to industrial customers and weather-adjusted KWH energy sales to commercial customers remained relatively flat.
Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the third quarter 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.
Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2010 when compared to the corresponding periods for 2009 primarily due to higher fuel and purchased power expenses in the third quarter of 2010. 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 effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Regulatory Matters” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$5.4
  21.2   $15.6   22.2
 
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 and Georgia utilities. Revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the third quarter 2010, wholesale revenues from non-affiliates were $31.2 million compared to $25.8 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 8.1% increase in KWH energy sales to serve weather-related increases in non-territorial demand and a 6.8% increase in price related to energy rates.
For year-to-date 2010, wholesale revenues from non-affiliates were $86.0 million compared to $70.4 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 11.8% increase in KWH energy sales to serve weather-related increases in non-territorial demand and a 9.0% increase in price related to energy rates.
Wholesale Revenues – Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$34.4   937.8   $68.7   347.6
 
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 2010, wholesale revenues from affiliates were $38.0 million compared to $3.6 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 661.7% increase in KWH energy sales resulting from the dispatch of available Gulf Power resources to serve affiliate demand and a 36.3% increase in price related to energy rates.
For year-to-date 2010, wholesale revenues from affiliates were $88.4 million compared to $19.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 257.8% increase in KWH energy sales resulting from the dispatch of available Gulf Power resources to serve affiliate demand and a 25.1% increase in price related to 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 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$(1.0)   (5.7)   $(7.4)   (13.6)
 
In the third quarter 2010, other revenues were $17.6 million compared to $18.6 million for the corresponding period in 2009. The decrease was primarily due to a $2.0 million decrease in revenues from other energy services, partially offset by higher franchise fees of $1.0 million.
For year-to-date 2010, other revenues were $47.4 million compared to $54.8 million for the corresponding period in 2009. The decrease was primarily due to a $9.7 million decrease in revenues from other energy services, partially offset by higher franchise fees of $2.4 million.
The decreased revenues from other energy services did not have a significant effect on net income since they were generally offset by related expenses. Franchise fees have no impact on net income.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Third Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ 73.7       45.1     $ 150.2       34.5  
Purchased power – non-affiliates
    2.8       27.8       14.1       69.0  
Purchased power – affiliates
    (9.1 )     (31.0 )     (6.3 )     (10.8 )
                     
Total fuel and purchased power expenses
  $ 67.4             $ 158.0          
                     
*   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 2010, total fuel and purchased power expenses were $270.0 million compared to $202.6 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $47.0 million increase related to total KWHs generated and purchased and a $20.4 million increase in the average cost of fuel and purchased power.
For year-to-date 2010, total fuel and purchased power expenses were $671.5 million compared to $513.5 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $116.9 million increase related to total KWHs generated and purchased and a $41.1 million increase as a result of an increase in the average cost of fuel and purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power’s fuel cost recovery and purchased power capacity cost recovery clauses. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Regulatory Matters” herein for additional information. See also MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Purchased Power Capacity Recovery” in Item 8 of the Form 10-K for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power’s cost of generation and purchased power are as follows:
                                                 
    Third Quarter   Third Quarter   Percent   Year-to-Date   Year-to-Date   Percent
Average Cost   2010   2009   Change   2010   2009   Change
    (cents per net KWH)           (cents per net KWH)        
Fuel
    5.09       4.59       10.9       5.04       4.46       13.0  
Purchased power
    7.93       7.98       (0.6 )     5.99       6.78       (11.7 )
 
In the third quarter 2010, fuel expense was $237.0 million compared to $163.3 million for the corresponding period in 2009. The increase was primarily due to a 16.4% increase in the average cost of coal and an 18.4% increase in KWHs generated as a result of increased demand, partially offset by a 4.4% decrease in the average cost of natural gas prices.
For year-to-date 2010, fuel expense was $585.2 million compared to $435.0 million for the corresponding period in 2009. The increase was primarily due to an 18.6% increase in the average cost of coal and a 7.4% increase in KWHs generated as a result of increased demand.
Non-Affiliates
In the third quarter 2010, purchased power expense from non-affiliates was $12.7 million compared to $9.9 million for the corresponding period in 2009. The increase was primarily due to a 752.9% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the fourth quarter 2009, partially offset by a 64.9% decrease in the average cost per KWH purchased.
For year-to-date 2010, purchased power expense from non-affiliates was $34.6 million compared to $20.5 million for the corresponding period in 2009. The increase was primarily due to a 576.9% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the fourth quarter 2009, partially offset by a 42.2% decrease in the average cost per KWH purchased.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Purchased Power Capacity Recovery” in Item 8 of the Form 10-K for additional information regarding the PPA that began in the fourth quarter 2009.
Energy purchases from non-affiliates will vary depending on the market cost of available energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.
Affiliates
In the third quarter 2010, purchased power expense from affiliates was $20.3 million compared to $29.4 million for the corresponding period in 2009. The decrease was primarily due to a 74.9% decrease in the volume of KWHs purchased, partially offset by a 204.7% increase in the average cost per KWH purchased.
For year-to-date 2010, purchased power expense from affiliates was $51.7 million compared to $58.0 million for the corresponding period in 2009. The decrease was primarily due to a 31.0% decrease in the volume of KWHs purchased, partially offset by a 35.7% increase in the average cost per KWH purchased.

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Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$9.8
  17.0   $7.3   3.7
 
In the third quarter 2010, other operations and maintenance expenses were $67.2 million compared to $57.4 million for the corresponding period in 2009. The increase was primarily due to increases in maintenance expense and labor.
For year-to-date 2010, other operations and maintenance expenses were $202.2 million compared to $194.9 million for the corresponding period in 2009. The increase was primarily due to increases in maintenance expense and labor, partially offset by a decrease in storm recovery costs.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
             
(change in millions)   (% change)   (change in millions)   (% change)
$10.5   45.1   $20.8   29.8
 
In the third quarter 2010, depreciation and amortization was $34.0 million compared to $23.5 million for the corresponding period in 2009. For year-to-date 2010, depreciation and amortization was $90.6 million compared to $69.8 million for the corresponding period in 2009. These increases were primarily due to the addition of an environmental control project at Plant Crist being placed into service in December 2009 and other net additions to generation.
Taxes Other Than Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$2.6   9.8   $6.5   9.0
 
In the third quarter 2010, taxes other than income taxes were $29.3 million compared to $26.7 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $78.6 million compared to $72.1 million for the corresponding period in 2009. These increases were primarily due to increases in property taxes, gross receipt taxes, and franchise fees. Gross receipt taxes and franchise fees have no impact on net income.
Allowance for Equity Funds Used During Construction
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$(5.4)   (79.1)   $(12.8)   (74.0)
 
In the third quarter 2010, AFUDC equity was $1.4 million compared to $6.8 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $4.5 million compared to $17.3 million for the corresponding period in 2009. These decreases were primarily due to an environmental control project at Plant Crist being placed into service in December 2009.

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Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$4.5   48.6   $9.3   32.0
 
In the third quarter 2010, interest expense, net of amounts capitalized was $13.8 million compared to $9.3 million for the corresponding period in 2009. For year-to-date 2010, interest expense, net of amounts capitalized was $38.3 million compared to $29.0 million for the corresponding period in 2009. These increases were primarily due to the change in capitalization of the AFUDC debt related to an environmental control project at Plant Crist being placed into service in December 2009 and an increase in long-term debt levels resulting from the issuance of additional senior notes in the first quarter 2010 to fund general corporate purposes, including Gulf Power’s continuous construction program.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$3.6   16.4   $14.8   32.7
 
In the third quarter 2010, income taxes were $25.7 million compared to $22.1 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $60.1 million compared to $45.3 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Changes in economic conditions impact sales for Gulf Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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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New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding notices of violation issued by the EPA relating to Gulf Power’s Plant Crist and a unit partially owned by Gulf Power at Plant Scherer and civil actions brought by the EPA against Alabama Power and Georgia Power alleging that these companies violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of their coal-fired generating facilities. Gulf Power is not a party to the cases involving Alabama Power and Georgia Power. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims in the case against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.
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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO2) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO2, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Gulf Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and nitrogen oxides (NOx) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Florida and Georgia, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Florida, Georgia, and Mississippi, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
These regulations could result in significant additional compliance and operational 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.
Coal Combustion Byproducts
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Gulf Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.
The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Gulf Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.
Florida PSC Matters
Retail Regulatory Matters
Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. If, at anytime during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the year, 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, 2010 totaled $16.6 million, compared to $2.4 million at December 31, 2009. 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 changes in the billing factor will not have a significant effect on Gulf Power’s revenues or net income, but will affect cash flow.
In November 2010, the Florida PSC approved Gulf Power’s annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2011. The net effect of the approved changes is a 2.8% rate decrease for residential customers using 1,000 KWHs per month.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

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Environmental Compliance Recovery
On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million and is scheduled for completion in the fourth quarter 2014. Gulf Power’s portion of the cost, if approved by the Florida PSC, is expected to be recovered through its environmental compliance recovery clause. Hearings on the certificate request are scheduled to be held with the Mississippi PSC on January 25, 2011 with a final order expected by February 28, 2011. The final outcome of this matter cannot now be determined.
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Gulf Power in Item 7 of the Form 10-K for additional information.
Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Gulf Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Gulf Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Gulf Power cannot be determined at this time.
Stimulus Funding
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Gulf Power will receive, and will match, $15.5 million under this agreement.
Income Tax Matters
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $6 million for Gulf Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility

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industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Gulf Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $37 million.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against 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.
The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Gulf Power’s service territory.
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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Gulf Power’s financial condition remained stable at September 30, 2010. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $255.0 million for the first nine months of 2010 compared to $148.2 million for the corresponding period in 2009. The $106.8 million increase in cash provided from operating activities was primarily due to an increase in cash from fossil fuel stock resulting from an increase in generation and a decrease in cash payments related to fuel inventory as well as an increase in deferred income taxes related to fuel cost recovery. The increase was partially offset by a decrease in collections attributable to regulatory fuel clause revenues. Net cash used for investing activities totaled $220.6 million in the first nine months of 2010 compared to $375.7 million for the corresponding period in 2009. Net cash provided from financing activities totaled $59.3 million for the first nine months of 2010 compared to $233.0 million for the corresponding period in 2009. The decreases of $155.1 million in investing activities and $173.7 million in financing activities were primarily due to an environmental control project at Plant Crist being placed into service in December 2009. 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 2010 include increases in cash and cash equivalents of $93.7 million, customer accounts receivable of $34.0 million, and accumulated deferred income taxes of $56.5 million. Total property, plant, and equipment increased by $146.8 million, primarily due to environmental control projects. Notes payable decreased by $90.3 million. Securities due within one year increased by $45.0 million due to the redemption of long-term debt.
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, scheduled maturities of long-term debt, interest, derivative obligations, preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $185 million will be required through September 30, 2011 to fund maturities and announced redemptions of long-term debt. Gulf Power met its obligations to redeem $75 million in senior notes subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Gulf Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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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 primarily utilized funds from operating cash flows, short-term debt, security issuances, a long-term bank note, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at September 30, 2010 cash and cash equivalents of approximately $102.3 million and unused committed credit arrangements with banks of $235 million. Of the cash and cash equivalents, approximately $12 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $50 million expire in 2010 and $185 million expire in 2011. Of these credit arrangements, $205 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. The 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. Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At September 30, 2010, Gulf Power had no commercial paper borrowings outstanding. During the third quarter 2010, Gulf Power had an average of $70 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $100 million. 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, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $574 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.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch rating of Gulf Power’s preferred and preference stock decreased from A- to BBB+. These ratings are not applicable to the collateral requirements described above.
On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Gulf Power (senior unsecured to A3 from A2). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Gulf Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Gulf Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Gulf Power (to Baa2 from Baa1). Moody’s announced that the ratings outlook for Gulf Power is stable.
Market Price Risk
Gulf Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (15 )   $ (14 )
Contracts realized or settled
    4       14  
Current period changes(a)
    (7 )     (18 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (18 )   $ (18 )
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $3 million and a decrease of $4 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Gulf Power had a net hedge volume of 14 million mmBtu with a weighted average contract cost of approximately $1.26 per mmBtu above market prices, compared to 9 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.61 per mmBtu above market prices and compared to 11 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.29 per mmBtu above market prices. Natural gas hedges 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
Regulatory hedges relate to Gulf Power’s fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.
Gulf Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (18 )     (13 )     (5 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (18 )   $ (13 )   $ (5 )   $  
 
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 Note 1 under “Financial Instruments” and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In the first nine months of 2010, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes.
In April 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term debt, and for general corporate purposes, including Gulf Power’s continuous construction program. Gulf Power settled $100 million of interest rate hedges related to the Series 2010A Senior Note issuance at a gain of approximately $1.5 million. The gain will be amortized to interest expense over 10 years.
In June 2010, Gulf Power incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer.
In September 2010, Gulf Power issued $125 million aggregate principal amount of its Series 2010B 5.10% Senior Notes due October 1, 2040. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power’s continuous construction program, and, subsequent to September 30, 2010, for the redemption of all of the $40 million aggregate principal amount of Gulf Power’s Series I 5.75% Senior

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Notes due September 15, 2033 and $35 million aggregate principal amount of Gulf Power’s Series J 5.875% Senior Notes due April 1, 2044.
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,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 230,977     $ 231,894     $ 620,658     $ 608,761  
Wholesale revenues, non-affiliates
    78,409       81,242       223,499       235,089  
Wholesale revenues, affiliates
    13,025       13,404       31,636       30,785  
Other revenues
    4,672       4,140       11,749       11,449  
 
                       
Total operating revenues
    327,083       330,680       887,542       886,084  
 
                       
Operating Expenses:
                               
Fuel
    154,607       148,115       388,979       393,912  
Purchased power, non-affiliates
    2,547       1,666       7,666       7,374  
Purchased power, affiliates
    10,902       21,946       60,113       65,346  
Other operations and maintenance
    65,953       61,138       205,055       182,500  
Depreciation and amortization
    20,106       17,707       57,567       53,382  
Taxes other than income taxes
    17,935       17,033       53,568       48,178  
 
                       
Total operating expenses
    272,050       267,605       772,948       750,692  
 
                       
Operating Income
    55,033       63,075       114,594       135,392  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    1,490             2,018       387  
Interest income
    49       34       122       829  
Interest expense, net of amounts capitalized
    (4,886 )     (6,075 )     (17,011 )     (17,091 )
Other income (expense), net
    1,099       474       3,272       2,852  
 
                       
Total other income and (expense)
    (2,248 )     (5,567 )     (11,599 )     (13,023 )
 
                       
Earnings Before Income Taxes
    52,785       57,508       102,995       122,369  
Income taxes
    18,759       22,177       37,631       46,268  
 
                       
Net Income
    34,026       35,331       65,364       76,101  
Dividends on Preferred Stock
    433       433       1,299       1,299  
 
                       
Net Income After Dividends on Preferred Stock
  $ 33,593     $ 34,898     $ 64,065     $ 74,802  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred Stock
  $ 33,593     $ 34,898     $ 64,065     $ 74,802  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $4, $(27), $8, and $-, respectively
    7       (44 )     13        
 
                       
Comprehensive Income
  $ 33,600     $ 34,854     $ 64,078     $ 74,802  
 
                       
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,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 65,364     $ 76,101  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    60,959       58,929  
Deferred income taxes
    (4,557 )     (27,430 )
Investment tax credits received
    14,352        
Allowance for equity funds used during construction
    (2,018 )     (387 )
Pension, postretirement, and other employee benefits
    6,657       5,817  
Stock based compensation expense
    1,053       822  
Generation construction screening costs
    (50,554 )     (21,955 )
Other, net
    (720 )     618  
Changes in certain current assets and liabilities —
               
-Receivables
    (21,003 )     (6,482 )
-Under recovered regulatory clause revenues
          54,994  
-Fossil fuel stock
    10,163       (42,838 )
-Materials and supplies
    (222 )     (1,782 )
-Prepaid income taxes
          1,061  
-Other current assets
    (2,503 )     (9,783 )
-Accounts payable
    25,819       (26,354 )
-Accrued taxes
    7,630       13,430  
-Accrued compensation
    427       (10,238 )
-Over recovered regulatory clause revenues
    14,939       20,466  
-Other current liabilities
    (442 )     228  
 
           
Net cash provided from operating activities
    125,344       85,217  
 
           
Investing Activities:
               
Property additions
    (125,980 )     (72,661 )
Cost of removal, net of salvage
    (7,613 )     (9,911 )
Construction payables
    6,903       (3,949 )
Other investing activities
    (6,693 )     (2,150 )
 
           
Net cash used for investing activities
    (133,383 )     (88,671 )
 
           
Financing Activities:
               
Decrease in notes payable, net
          (24,891 )
Proceeds —
               
Capital contributions from parent company
    3,920       3,330  
Senior notes issuances
          125,000  
Other long-term debt issuances
    125,000        
Redemptions —
               
Capital leases
    (988 )      
Senior notes
          (40,000 )
Payment of preferred stock dividends
    (1,299 )     (1,299 )
Payment of common stock dividends
    (51,450 )     (51,375 )
Other financing activities
    (614 )     (1,714 )
 
           
Net cash provided from financing activities
    74,569       9,051  
 
           
Net Change in Cash and Cash Equivalents
    66,530       5,597  
Cash and Cash Equivalents at Beginning of Period
    65,025       22,413  
 
           
Cash and Cash Equivalents at End of Period
  $ 131,555     $ 28,010  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $1,482 and $117 capitalized for 2010 and 2009, respectively)
  $ 16,726     $ 15,824  
Income taxes (net of refunds)
  $ 11,345     $ 48,008  
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   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 131,555     $ 65,025  
Receivables —
               
Customer accounts receivable
    45,923       36,766  
Unbilled revenues
    30,233       27,168  
Other accounts and notes receivable
    7,131       11,337  
Affiliated companies
    51,368       13,215  
Accumulated provision for uncollectible accounts
    (1,006 )     (940 )
Fossil fuel stock, at average cost
    117,074       127,237  
Materials and supplies, at average cost
    28,014       27,793  
Other regulatory assets, current
    64,823       53,273  
Prepaid income taxes
    37,925       32,237  
Other current assets
    16,094       12,625  
 
           
Total current assets
    529,134       405,736  
 
           
Property, Plant, and Equipment:
               
In service
    2,370,635       2,316,494  
Less accumulated provision for depreciation
    975,536       950,373  
 
           
Plant in service, net of depreciation
    1,395,099       1,366,121  
Construction work in progress
    198,977       48,219  
 
           
Total property, plant, and equipment
    1,594,076       1,414,340  
 
           
Other Property and Investments
    6,120       7,018  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    13,638       8,536  
Other regulatory assets, deferred
    149,175       209,100  
Other deferred charges and assets
    30,767       27,951  
 
           
Total deferred charges and other assets
    193,580       245,587  
 
           
Total Assets
  $ 2,322,910     $ 2,072,681  
 
           
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   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 206,409     $ 1,330  
Accounts payable —
               
Affiliated
    58,410       49,209  
Other
    64,925       38,662  
Customer deposits
    12,142       11,143  
Accrued taxes —
               
Accrued income taxes
    25,823       10,590  
Other accrued taxes
    42,021       49,547  
Accrued interest
    4,405       5,739  
Accrued compensation
    14,212       13,785  
Other regulatory liabilities, current
    5,655       7,610  
Over recovered regulatory clause liabilities
    63,534       48,596  
Liabilities from risk management activities
    29,762       19,454  
Other current liabilities
    24,780       21,142  
 
           
Total current liabilities
    552,078       276,807  
 
           
Long-term Debt
    412,539       493,480  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    230,058       223,066  
Deferred credits related to income taxes
    12,121       13,937  
Accumulated deferred investment tax credits
    26,286       12,825  
Employee benefit obligations
    166,495       161,778  
Other cost of removal obligations
    107,615       97,820  
Other regulatory liabilities, deferred
    57,014       54,576  
Other deferred credits and liabilities
    49,214       47,090  
 
           
Total deferred credits and other liabilities
    648,803       611,092  
 
           
Total Liabilities
    1,613,420       1,381,379  
 
           
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
    331,122       325,562  
Retained earnings
    307,884       295,269  
Accumulated other comprehensive income (loss)
    13        
 
           
Total common stockholder’s equity
    676,710       658,522  
 
           
Total Liabilities and Stockholder’s Equity
  $ 2,322,910     $ 2,072,681  
 
           
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 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, 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 customer prices will continue to challenge Mississippi Power for the foreseeable future.
On June 3, 2010, the Mississippi PSC issued a certification of public convenience and necessity authorizing the acquisition, construction, and operation of a new electric generating plant located in Kemper County, Mississippi, which is scheduled to be placed into service in 2014.
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 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.3)   (3.7)   $(10.7)   (14.4)
 
Mississippi Power’s net income after dividends on preferred stock for the third quarter 2010 was $33.6 million compared to $34.9 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for the third quarter 2010 was primarily due to a decrease in wholesale energy and capacity revenues from customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation and amortization. The decrease in net income after dividends on preferred stock for the third quarter 2010 was partially offset by increases in AFUDC equity and territorial base revenues primarily resulting from warmer weather in the third quarter 2010 compared to the third quarter 2009 and a decrease in interest expense, net of amounts capitalized.
Mississippi Power’s net income after dividends on preferred stock for year-to-date 2010 was $64.1 million compared to $74.8 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for year-to-date 2010 was primarily due to a decrease in wholesale energy and capacity revenues from customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation and amortization. The decrease in net income after dividends on preferred stock for year-to-date 2010 was partially offset by increases in AFUDC equity and territorial base revenues primarily resulting from warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 compared to the corresponding period in 2009.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Third Quarter 2010 vs. Third Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.9)   (0.4)   $11.9   2.0
 
In the third quarter 2010, retail revenues were $231.0 million compared to $231.9 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $620.7 million compared to $608.8 million for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Third Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
 
Retail – prior year
  $ 231.9             $ 608.8          
Estimated change in —
                               
Rates and pricing
                0.2        
Sales growth (decline)
    (1.0 )     (0.5 )     (3.1 )     (0.5 )
Weather
    3.9       1.7       13.2       2.2  
Fuel and other cost recovery
    (3.8 )     (1.6 )     1.6       0.3  
 
Retail – current year
  $ 231.0       (0.4 )%   $ 620.7       2.0 %
 
Revenues associated with changes in rates and pricing in the third quarter 2010 when compared to the corresponding period in 2009 were not material.
Revenues associated with changes in rates and pricing increased year-to-date 2010 when compared to the corresponding period in 2009 primarily due to an increase of $1.0 million related to the ECO Plan rate, partially offset by a decrease of $0.8 million related to System Restoration Rider (SRR) revenues pursuant to an order from the Mississippi PSC.
For additional information on SRR, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K.
Revenues attributable to changes in sales decreased in the third quarter 2010 when compared to the corresponding period in 2009. Weather-adjusted KWH energy sales to residential customers decreased 2.2% primarily due to the lack of growth in the number of residential customers in Mississippi Power’s service territory. KWH energy sales to industrial customers decreased 0.2% as a result of a change in operations for one of the larger industrial customers and a maintenance outage for another large customer.
Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. Weather-adjusted KWH energy sales to residential customers slightly increased due to increases in customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 3.0% primarily due to the declining number of commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 3.7% as a result of increased production for several large industrial customers due to improving economic conditions.
Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

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MISSISSIPPI 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 2010 when compared to the corresponding period in 2009 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to ad valorem taxes. Fuel and other cost recovery revenues increased year-to-date 2010 when compared to the corresponding period in 2009 primarily as a result of an increase in revenues related to ad valorem taxes, partially offset by lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.8)   (3.5)   $(11.6)   (4.9)
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Mississippi Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the third quarter 2010, wholesale revenues from non-affiliates were $78.4 million compared to $81.2 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $5.0 million, partially offset by a $2.2 million increase in revenues from customers inside Mississippi Power’s service territory. The $5.0 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $6.3 million decrease in sales volume, partially offset by a $1.2 million increase associated with higher prices resulting from the higher marginal cost of fuel and a $0.1 million increase in capacity revenues. The $2.2 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $0.1 million increase in fuel revenues and a $2.1 million increase in wholesale base revenues resulting from warmer weather in the third quarter 2010 when compared to the corresponding period in 2009.
For year-to-date 2010, wholesale revenues from non-affiliates were $223.5 million compared to $235.1 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $21.3 million, partially offset by a $9.7 million increase in revenues from customers inside Mississippi Power’s service territory. The $21.3 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $25.1 million decrease in sales volume, partially offset by a $3.5 million increase associated with higher prices resulting from the higher marginal cost of fuel and a $0.3 million increase in capacity revenues. The $9.7 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $4.4 million increase in fuel revenues and a $5.3 million increase in wholesale base revenues resulting from warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.
Wholesale Revenues – Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.4)   (2.8)   $0.9   2.8
 
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the third quarter 2010, wholesale revenues from affiliates were $13.0 million compared to $13.4 million for the corresponding period in 2009. The decrease was primarily due to a $5.1 million decrease in capacity revenues primarily due to affiliated companies purchasing capacity from third parties rather than from Mississippi Power, partially offset by a $4.7 million increase in energy revenues, of which $3.3 million was associated with higher prices and an increase of $1.4 million associated with increased sales volume.
For year-to-date 2010, wholesale revenues from affiliates were $31.6 million compared to $30.8 million for the corresponding period in 2009. The increase was primarily due to a $5.5 million increase in energy revenues, of which $4.4 million was associated with higher prices and $1.1 million associated with increased sales volume. This increase was partially offset as capacity revenues decreased $4.6 million primarily due to affiliated companies purchasing capacity from third parties rather than from Mississippi Power.
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Third Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel
  $ 6.5       4.4     $ (4.9 )     (1.3 )
Purchased power – non-affiliates
    0.8       52.8       0.3       4.0  
Purchased power – affiliates
    (11.0 )     (50.3 )     (5.2 )     (8.0 )
                 
Total fuel and purchased power expenses
  $ (3.7 )           $ (9.8 )        
                 
In the third quarter 2010, total fuel and purchased power expenses were $168.0 million compared to $171.7 million for the corresponding period in 2009. The decrease was primarily due to a $9.9 million decrease in the cost of fuel and purchased power, partially offset by a $6.2 million increase related to the total KWHs generated and purchased.
For year-to-date 2010, total fuel and purchased power expenses were $456.8 million compared to $466.6 million for the corresponding period in 2009. The decrease was primarily due to a $10.0 million decrease in the cost of fuel and purchased power, partially offset by a $0.2 million increase related to the total KWHs generated and purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Retail Regulatory Matters” herein for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Mississippi 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   2010   2009   Change   2010   2009   Change
    (cents per net KWH)           (cents per net KWH)        
 
Fuel
    4.08       4.38       (6.8 )     4.21       4.34       (3.0 )
Purchased power
    4.04       3.62       11.6       3.72       3.62       2.8  
 
In the third quarter 2010, fuel expense was $154.6 million compared to $148.1 million for the corresponding period in 2009. The increase was primarily due to a 12.0% increase in generation from Mississippi Power facilities resulting from higher system load, partially offset by a 6.8% decrease in the price of fuel resulting from lower coal prices.
For year-to-date 2010, fuel expense was $388.9 million compared to $393.9 million for the corresponding period in 2009. The decrease was primarily due to a 3.0% decrease in the price of fuel resulting from lower coal prices, partially offset by a 1.8% increase in generation from Mississippi Power facilities resulting from higher system load.
Non-Affiliates
In the third quarter 2010, purchased power expense from non-affiliates was $2.5 million compared to $1.7 million for the corresponding period in 2009. The increase was primarily the result of a 249.5% increase in the average cost per KWH purchased, partially offset by a 56.3% decrease in the volume of KWH purchased. The decrease in the volume of KWH purchased was the result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.
For year-to-date 2010, purchased power expense from non-affiliates was $7.7 million compared to $7.4 million for the corresponding period in 2009. The increase was primarily the result of a 205.3% increase in the average cost per KWH purchased, partially offset by a 66.0% decrease in the volume of KWH purchased. The decrease in the volume of KWH purchased was a result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.
Energy purchases from non-affiliates will vary depending on the market cost of available energy compared to the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.
Affiliates
In the third quarter 2010, purchased power expense from affiliates was $10.9 million compared to $21.9 million for the corresponding period in 2009. The decrease was primarily due to a 48.1% decrease in the volume of KWH purchased and a 4.3% decrease in the average cost per KWH purchased.
For year-to-date 2010, purchased power expense from affiliates was $60.1 million compared to $65.3 million for the corresponding period in 2009. The decrease was primarily due to a 14.3% decrease in the average cost per KWH purchased, partially offset by a 7.3% increase in the volume of KWH purchased.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$4.8   7.9   $22.5   12.4
 
In the third quarter 2010, other operations and maintenance expenses were $65.9 million compared to $61.1 million for the corresponding period in 2009. The increase was primarily due to increases in labor costs of $2.8 million, distribution maintenance for vegetation management costs of $0.4 million, and administrative and general expenses of $1.4 million.
For year-to-date 2010, other operations and maintenance expenses were $205.0 million compared to $182.5 million for the corresponding period in 2009. The increase was primarily due to a $7.8 million increase in generation maintenance expenses for several major outages, a $3.3 million increase in routine generation expenses, a $3.8 million increase in transmission and distribution expenses related to substation and overhead line maintenance and vegetation management costs, a $3.1 million increase in administrative and general expenses, and a $5.3 million increase in labor costs.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$2.4   13.5   $4.2   7.8
 
In the third quarter 2010, depreciation and amortization was $20.1 million compared to $17.7 million for the corresponding period in 2009. The increase was primarily due to a $1.6 million increase in ECO Plan amortization from the prior year and a $0.8 million increase in depreciation resulting from an increase in plant in service.
For year-to-date 2010, depreciation and amortization was $57.6 million compared to $53.4 million for the corresponding period in 2009. The increase was primarily due to a $2.2 million increase in ECO Plan amortization from the prior year and a $2.0 million increase in depreciation resulting from an increase in plant in service.
Taxes Other Than Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$0.9   5.3   $5.4   11.2
 
In the third quarter 2010, taxes other than income taxes were $17.9 million compared to $17.0 million for the corresponding period in 2009. The increase was primarily due to a $0.8 million increase in ad valorem taxes and a $0.1 million increase in payroll taxes.
For year-to-date 2010, taxes other than income taxes were $53.6 million compared to $48.2 million for the corresponding period in 2009. The increase was primarily due to increases in ad valorem taxes of $4.8 million, payroll taxes of $0.4 million, and franchise taxes of $0.2 million.
The retail portion of the increase in ad valorem taxes is recoverable under Mississippi Power’s ad valorem tax cost recovery clause and, therefore, does not affect net income.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.5   N/M   $1.6   N/M
 
 
N/M – Not meaningful
In the third quarter 2010, AFUDC equity was $1.5 million compared to $0 for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $2.0 million compared to $0.4 million for the corresponding period in 2009. These increases were due to the Kemper IGCC project.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(1.2)   (19.6)   $(0.1)   (0.5)
 
In the third quarter 2010, interest expense, net of amounts capitalized was $4.9 million compared to $6.1 million for the corresponding period in 2009. The decrease was primarily due to a $1.3 million increase in AFUDC debt primarily associated with the Kemper IGCC project, partially offset by a $0.2 million increase primarily related to higher interest expense related to a regulatory recovery mechanism for fuel and energy cost hedging and the issuance of new debt in September 2010.
For year-to-date 2010, interest expense, net of amounts capitalized was $17.0 million compared to $17.1 million for the corresponding period in 2009. The slight decrease was primarily due to a $1.4 million increase in AFUDC debt primarily associated with the Kemper IGCC project, partially offset by a $0.9 million increase in interest expense associated with the issuance of new debt in March 2009 and September 2010 and a $0.4 million increase in interest expense related to a regulatory recovery mechanism for fuel and energy cost hedging.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Mississippi Power in Item 7 of the Form 10-K.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(3.4)   (15.4)   $(8.7)   (18.7)
 
In the third quarter 2010, income taxes were $18.8 million compared to $22.2 million for the corresponding period in 2009. The decrease in income taxes was primarily due to a $1.7 million decrease resulting from lower pre-tax income, a $1.1 million decrease due to actualization of the 2009 tax return in the third quarter 2010, and a $0.6 million decrease due to an increase in AFUDC equity.
For year-to-date 2010, income taxes were $37.6 million compared to $46.3 million for the corresponding period in 2009. The decrease was primarily due to a $6.9 million decrease resulting from lower pre-tax income, a $1.1 million decrease due to actualization of the 2009 tax return in the third quarter 2010, a $1.1 million decrease in unrecognized tax benefits, a $0.8 million decrease due to an increase in AFUDC equity, partially offset by a $0.5 million increase due to a lower production activities deduction, and a $0.9 million increase due to a lower Mississippi manufacturing investment tax credit.

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MISSISSIPPI 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 Mississippi Power’s future earnings potential. The level of Mississippi Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include Mississippi Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all 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 Mississippi Power’s service area. Changes in economic conditions impact sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi 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 Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding a civil action brought by the EPA alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi 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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO2) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO2, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Mississippi Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO2 and nitrogen oxides (NOx) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO2 and NOx from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama and Mississippi, to achieve additional reductions in NOx emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.
These regulations could result in significant additional compliance and operational 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.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Coal Combustion Byproducts
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Mississippi Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.
The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Mississippi Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
Global Climate Issues
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Mississippi Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC and Mississippi PSC Matters
Wholesale Rate Filing
On October 22, 2010, Mississippi Power filed a request with the FERC for a revised wholesale electric tariff and revised rates. Prior to making this filing, Mississippi Power reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provides for an increase in annual base wholesale revenues in the amount of approximately $4.1 million, effective January 1, 2011. In addition, the settlement agreement allows Mississippi Power to implement an emissions allowance cost clause, effective January 1, 2011. The emissions allowance cost clause contains an over and under recovery provision similar to the fuel recovery clause and is projected to collect $6.9 million in 2011. The settlement agreement also provides for collection of up to $2.8 million of 2010 emissions allowance expense for the period of September 1, 2010 through December 31, 2010 and allows Mississippi Power to defer the wholesale portion of the income tax expense associated with the change in taxability of the federal subsidy under the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.
In November 2009, the revised PEP was approved by the Mississippi PSC and Mississippi Power resumed annual evaluations. Mississippi Power filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change.
On March 15, 2010, Mississippi Power submitted its annual PEP lookback filing for 2009, which recommended no surcharge or refund. On October 26, 2010, Mississippi Power and the Mississippi Public Utilities Staff agreed and stipulated that no surcharge or refund is required. On November 2, 2010, the Mississippi PSC accepted the stipulation.
System Restoration Rider
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K for additional information.
In September 2009, the Mississippi PSC issued an order requiring Mississippi Power to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million. The revised factors were in effect from November 2009 to March 2010. Beginning in April 2010, the SRR factors were reset to zero. On January 29, 2010, Mississippi Power submitted its 2010 SRR rate filing with the Mississippi PSC and expects to accrue approximately $3.0 million to the property damage reserve in 2010.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On February 12, 2010, Mississippi Power submitted its 2010 ECO Plan notice which proposed an increase in annual revenues for Mississippi Power of approximately $3.9 million. Due to changes in ECO Plan cost projections, on August 20, 2010, Mississippi Power submitted a revised 2010 ECO Plan which reduced the requested increase in annual revenues to $1.7 million. In its 2010 ECO Plan filing, Mississippi Power proposed to change the true-up provision of the ECO Plan rate schedule to consider actual revenues collected in addition to actual costs. Hearings on the ECO Plan were held with the Mississippi PSC on October 5, 2010. On October 25, 2010, the Mississippi PSC held a public meeting to discuss the 2010 ECO Plan and issued an order approving the revised 2010 ECO Plan with the new rates effective in November 2010. Mississippi Power and the Mississippi Public Utilities Staff jointly agreed to defer the decision on the change in the true-up provision of the ECO Plan rate schedule. The ultimate outcome of the proposed changes to the true-up provision cannot be determined at this time.
On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million and is scheduled for completion in the fourth quarter 2014. Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through its ECO Plan. On October 25, 2010, the Mississippi PSC held a public meeting to discuss Mississippi Power’s filing and issued a scheduling order for the request for a certificate of public convenience and necessity for the project. Hearings on the certificate request are scheduled to be held on January 25, 2011 with a final order expected by February 28, 2011. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes an annual retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2009. The Mississippi PSC approved the retail fuel cost recovery factor on December 15, 2009 with the new rates effective January 2010. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 11.3% of total 2009 retail revenues. As of September 30, 2010, the amount of over recovered retail fuel costs included in the balance sheet was $44.1 million compared to $29.4 million at December 31, 2009. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2010, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 20.9% of total 2009 MRA revenue. Effective February 1, 2010, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 16.9% of total 2009 MB revenue. As of September 30, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheet was $15.9 million and $3.5 million, respectively, compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will not have a significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.
In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the retail fuel adjustment clause and energy cost management clause for 2010. The audit is scheduled to be completed in early 2011. The ultimate outcome of this matter cannot be determined at this time.
Depreciation Study
See Note 1 to the financial statements of Mississippi Power under “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information. In September 2009, Mississippi Power filed a depreciation study, as of December 31,

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2008, with the Mississippi PSC and the FERC. The FERC accepted this study in October 2009. On April 20, 2010, the Mississippi PSC issued an order approving the depreciation rates effective January 1, 2010.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” and “PSC Matters – Mississippi Baseload Construction Legislation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.
On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the Kemper IGCC, which modifies the original PSD air permit issued in October 2008. The Mississippi Chapter of the Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit.
In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. On September 30, 2010, Mississippi Power and the IRS executed the closing agreement for the Phase II tax credits. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits. In order to remain eligible for the Phase II tax credits, Mississippi Power must capture and sequester at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits, and must meet the required in-service date, satisfy environmental and other permitting requirements, and have in place a binding contract for the steam turbine generator.
On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the Kemper IGCC did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power. The April 2010 order also approved recovery of $46 million of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of SCS, which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million has been incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010 will be reviewed and addressed in a future proceeding.
On May 10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order.
On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved the alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the State of Mississippi Baseload Act of 2008 (Baseload Act), which provides for the accrual of allowance for funds used during construction in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by

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Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and will acquire mineral reserves located at the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation.
On June 17, 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant a certificate of public convenience and necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by Mississippi Power on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied Mississippi Power’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court.
On July 27, 2010, Mississippi Power and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.
On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the Clean Coal Power Initiative Round 2 (CCPI2) grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for Mississippi Power to receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during the initial operation of the Kemper IGCC.
As of September 30, 2010, Mississippi Power had spent a total of $195.5 million on the Kemper IGCC, including regulatory filing costs. Of this total, $156.4 million was included in CWIP (net of $24.8 million recorded as a receivable of CCPI2 grant funds), $11.5 million was recorded in other regulatory assets, $1.3 million was recorded in other deferred charges and assets, and $1.5 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed.
The ultimate outcome of these matters cannot be determined at this time.
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Mississippi Power in Item 7 of the Form 10-K for additional information.

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Healthcare Reform
On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Mississippi Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of regulatory treatment, this change had no material impact on the financial statements of Mississippi Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Mississippi Power cannot be determined at this time.
Stimulus Funding
On April 8, 2010, Mississippi Power received notice that an award had been granted under the American Recovery and Reinvestment Act of 2009 (ARRA) grant application for smart grid workforce training. Under this agreement, Mississippi Power was to receive, and match, $2.6 million. Mississippi Power withdrew its application on September 17, 2010.
On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the ARRA. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Mississippi Power will receive, and will match, $25 million under this agreement.
Income Tax Matters
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $3 million for Mississippi Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

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Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Mississippi Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $16 million.
Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi 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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Mississippi 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 Mississippi Power’s financial statements.
The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Mississippi Power’s service territory.
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
Mississippi 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 Mississippi 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 Mississippi 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 Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, Plant Daniel Operating Lease, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Mississippi Power’s financial condition remained stable at September 30, 2010. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

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Net cash provided from operating activities totaled $125.3 million for the first nine months of 2010, compared to $85.2 million for the corresponding period in 2009. The $40.1 million increase in cash provided from operating activities was primarily due to an increase in cash from fossil fuel stock of $53.0 million primarily resulting from a decrease in cash payments related to fuel inventory, an increase in accounts payable of $52.1 million primarily due to timing of cash payments, an increase of $22.9 million in deferred income taxes primarily due to fuel cost recovery and a change in the tax method of accounting for repair costs, and an increase of $14.4 million related to an investment tax credit on the Kemper IGCC. These increases in cash were partially offset by an increase in spending related to the Kemper IGCC generation construction screening costs of $28.6 million and a decrease in cash related to lower fuel rates effective in the first quarter 2010. Net cash used for investing activities totaled $133.4 million for the first nine months of 2010, compared to $88.7 million for the corresponding period in 2009. The $44.7 million increase in net cash used for investing activities was primarily due to an increase in property additions primarily related to the Kemper IGCC. Net cash provided from financing activities totaled $74.6 million for the first nine months of 2010, compared to $9.1 million for the corresponding period in 2009. The $65.5 million increase in net cash provided from financing activities was primarily due to a $24.9 million decrease in notes payable and the repayment of $40.0 million of senior notes both of which occurred in the third quarter 2009. 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 2010 include an increase in cash and cash equivalents of $66.5 million. Affiliated companies receivables increased $38.2 million primarily due to funds to be received from the DOE related to the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for additional information. Total property, plant, and equipment increased by $179.7 million primarily due to the increase in construction work in progress related to the Kemper IGCC. The expenditures associated with the Kemper IGCC project were reclassified from other regulatory assets, deferred to construction work in progress during the second quarter 2010 upon the Mississippi PSC issuance of the final certificate order for the project. Securities due within one year increased by $205.1 million primarily due to the reclassification of a long-term bank loan maturing in March 2011 and a new $125.0 million bank loan maturing in September 2011. Accounts payable, other increased $26.3 million primarily due to the timing of payments and accrued income taxes increased $15.2 million primarily due to the tax accrual for 2010.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $206.4 million will be required through September 30, 2011 to fund maturities of long-term debt. No mandatory contributions to Mississippi Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Mississippi 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 Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance the DOE will issue federal loan guarantees to Mississippi Power. In addition, Mississippi Power has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used for the initial operation of the Kemper IGCC. In the third quarter 2010, Mississippi Power recorded a receivable of $24.8 million associated with this grant.
Mississippi Power’s current liabilities sometimes 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, Mississippi Power had at September 30, 2010 cash and cash equivalents of $131.6 million and unused committed credit arrangements with banks of $161 million. Of the cash and cash equivalents, approximately $125 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $16 million expire in 2010 and $145 million expire in 2011. Of these credit arrangements, $41 million contain provisions allowing two-year term loans executable at expiration and $65 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi 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. Mississippi 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 Mississippi Power and other Southern Company subsidiaries. At September 30, 2010, Mississippi Power had no commercial paper borrowings outstanding. During the third quarter 2010, Mississippi Power had an average of $37 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $63 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper, 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 Mississippi Power in Item 7 and Note 7 to the financial statements of Mississippi Power 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. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time.

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Credit Rating Risk
Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $381 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 Mississippi Power’s ability to access capital markets, particularly the short-term debt market.
On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch rating of Mississippi Power’s preferred stock decreased from A+ to A. These ratings are not applicable to the collateral requirements described above.
On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A2 from A1). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Mississippi Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Mississippi Power to VMIG-2 from VMIG-1 and the preferred stock ratings of Mississippi Power (to Baa1 from A3). Moody’s announced that the ratings outlook for Mississippi Power is stable.
On September 3, 2010, Fitch downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A+ from AA- and issuer default rating to A from A+). Fitch also announced that it had downgraded the short-term ratings of Mississippi Power to F1 from F1+. In addition, Fitch announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A+ from AA- and the preferred stock ratings of Mississippi Power (to A- from A). Fitch announced that the ratings outlook for Mississippi Power is stable.
Market Price Risk
Mississippi Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi 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.
In the second quarter 2010, Mississippi Power entered into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Mississippi Power had no material change in market risk exposure in the third quarter 2010 as a result of entering into these contracts.
Due to cost-based rate regulation, Mississippi 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, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

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The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (48 )   $ (42 )
Contracts realized or settled
    9       26  
Current period changes(a)
    (15 )     (38 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (54 )   $ (54 )
 
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $6 million and a decrease of $12 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to the price of natural gas. At September 30, 2010, Mississippi Power had a net hedge volume of 20 million mmBtu with a weighted average contract cost of approximately $2.80 per mmBtu above market prices, compared to 22 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $2.24 per mmBtu above market prices and compared to 23 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.83 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the energy cost management clause.
Regulatory hedges relate to Mississippi 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 energy cost management clause.
Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.
Mississippi 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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010  
    Fair Value Measurements  
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (54 )     (30 )     (24 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (54 )   $ (30 )   $ (24 )   $  
 
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 Mississippi Power in Item 7 and Note 1 under “Financial Instruments” and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activities
In September 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay a portion of Mississippi Power’s short-term indebtedness and for general corporate purposes, including Mississippi Power’s continuous construction program.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, Mississippi 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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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Wholesale revenues, non-affiliates
  $ 261,551     $ 133,032     $ 568,877     $ 318,521  
Wholesale revenues, affiliates
    93,062       147,921       287,603       420,923  
Other revenues
    2,217       2,416       5,314       6,040  
 
                       
Total operating revenues
    356,830       283,369       861,794       745,484  
 
                       
Operating Expenses:
                               
Fuel
    120,466       58,820       294,658       176,332  
Purchased power, non-affiliates
    24,939       20,019       59,103       66,279  
Purchased power, affiliates
    31,454       20,915       79,874       49,977  
Other operations and maintenance
    34,614       29,094       111,499       97,033  
Depreciation and amortization
    29,361       23,190       87,362       74,727  
Taxes other than income taxes
    4,071       4,166       14,314       13,714  
 
                       
Total operating expenses
    244,905       156,204       646,810       478,062  
 
                       
Operating Income
    111,925       127,165       214,984       267,422  
Other Income and (Expense):
                               
Interest expense, net of amounts capitalized
    (18,801 )     (21,438 )     (58,408 )     (64,589 )
Other income (expense), net
    (113 )     2,699       198       2,465  
 
                       
Total other income and (expense)
    (18,914 )     (18,739 )     (58,210 )     (62,124 )
 
                       
Earnings Before Income Taxes
    93,011       108,426       156,774       205,298  
Income taxes
    31,317       41,146       50,566       79,048  
 
                       
Net Income
  $ 61,694     $ 67,280     $ 106,208     $ 126,250  
 
                       
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Nine Months  
    Ended September 30,     Ended September 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
 
Net Income
  $ 61,694     $ 67,280     $ 106,208     $ 126,250  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $1,125, $(298), $1,536, and $4, respectively
    1,759       (459 )     2,400       7  
Reclassification adjustment for amounts included in net income, net of tax of $1,018, $948, $3,011, and $2,814, respectively
    1,590       1,461       4,703       4,336  
 
                       
Total other comprehensive income (loss)
    3,349       1,002       7,103       4,343  
 
                       
Comprehensive Income
  $ 65,043     $ 68,282     $ 113,311     $ 130,593  
 
                       
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Nine Months  
    Ended September 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 106,208     $ 126,250  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    97,469       83,890  
Deferred income taxes
    13,251       8,020  
Convertible investment tax credits received
    22,150        
Deferred revenues
    18,846       33,290  
Mark-to-market adjustments
    2,435       (406 )
Accumulated billings on construction contract
    401       35,565  
Accumulated costs on construction contract
    (49 )     (39,890 )
Other, net
    2,014       2,611  
Changes in certain current assets and liabilities —
               
-Receivables
    (35,537 )     (44,195 )
-Fossil fuel stock
    6,097       2,215  
-Materials and supplies
    3,216       (4,110 )
-Prepaid income taxes
    2,013        
-Other current assets
    598       396  
-Accounts payable
    (2,194 )     (20,777 )
-Accrued taxes
    31,069       62,260  
-Accrued interest
    (12,194 )     (12,152 )
-Other current liabilities
    21       (199 )
 
           
Net cash provided from operating activities
    255,814       232,768  
 
           
Investing Activities:
               
Property additions
    (210,599 )     (47,696 )
Sale of property
    4,000       52  
Change in construction payables
    31,021       6,915  
Payments pursuant to long-term service agreements
    (30,936 )     (26,118 )
Other investing activities
    (248 )     (184 )
 
           
Net cash used for investing activities
    (206,762 )     (67,031 )
 
           
Financing Activities:
               
Increase in notes payable, net
    20,216        
Proceeds — Capital contributions
    3,908       2,068  
Payment of common stock dividends
    (80,325 )     (79,575 )
 
           
Net cash used for financing activities
    (56,201 )     (77,507 )
 
           
Net Change in Cash and Cash Equivalents
    (7,149 )     88,230  
Cash and Cash Equivalents at Beginning of Period
    7,152       37,894  
 
           
Cash and Cash Equivalents at End of Period
  $ 3     $ 126,124  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $7,704 and $441 capitalized for 2010 and 2009, respectively)
  $ 63,560     $ 68,652  
Income taxes (net of refunds)
  $ (8,158 )   $ 20,467  
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                       
    At September 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 3     $ 7,152  
Receivables —
               
Customer accounts receivable
    77,125       28,873  
Other accounts receivable
    1,890       2,064  
Affiliated companies
    34,792       38,561  
Fossil fuel stock, at average cost
    10,189       15,351  
Materials and supplies, at average cost
    32,416       31,607  
Prepaid service agreements — current
    20,459       44,090  
Prepaid income taxes
    3,245       5,177  
Other prepaid expenses
    2,577       3,176  
Assets from risk management activities
    6,103       4,901  
Other current assets
          6,754  
 
           
Total current assets
    188,799       187,706  
 
           
Property, Plant, and Equipment:
               
In service
    3,026,358       2,994,463  
Less accumulated provision for depreciation
    507,266       439,457  
 
           
Plant in service, net of depreciation
    2,519,092       2,555,006  
Construction work in progress
    361,223       153,982  
 
           
Total property, plant, and equipment
    2,880,315       2,708,988  
 
           
Other Property and Investments:
               
Goodwill
    1,839       1,794  
Other intangible assets, net of amortization of $498 and $17
at September 30, 2010 and December 31, 2009, respectively
    48,622       49,102  
 
           
Total other property and investments
    50,461       50,896  
 
           
Deferred Charges and Other Assets:
               
Prepaid long-term service agreements
    83,858       74,513  
Other deferred charges and assets — affiliated
    3,341       3,540  
Other deferred charges and assets — non-affiliated
    16,410       17,410  
 
           
Total deferred charges and other assets
    103,609       95,463  
 
           
Total Assets
  $ 3,223,184     $ 3,043,053  
 
           
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                       
    At September 30,     At December 31,  
Liabilities and Stockholder’s Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Notes payable
  $ 139,164     $ 118,948  
Accounts payable —
               
Affiliated
    80,438       58,493  
Other
    42,981       31,128  
Accrued taxes —
               
Accrued income taxes
    15,163       1,449  
Other accrued taxes
    14,248       2,576  
Accrued interest
    17,729       29,923  
Liabilities from risk management activities
    7,405       8,119  
Other current liabilities
    22       323  
 
           
Total current liabilities
    317,150       250,959  
 
           
Long-term Debt
    1,297,797       1,297,607  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    255,847       238,293  
Deferred convertible investment tax credits
    44,958       16,800  
Deferred capacity revenues — affiliated
    52,798       36,369  
Other deferred credits and liabilities — affiliated
    4,873       5,651  
Other deferred credits and liabilities — non-affiliated
    17,745       2,252  
 
           
Total deferred credits and other liabilities
    376,221       299,365  
 
           
Total Liabilities
    1,991,168       1,847,931  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $.01 per share —
               
Authorized - 1,000,000 shares
               
Outstanding - 1,000 shares
           
Paid-in capital
    868,370       864,462  
Retained earnings
    377,944       352,061  
Accumulated other comprehensive loss
    (14,298 )     (21,401 )
 
           
Total common stockholder’s equity
    1,232,016       1,195,122  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,223,184     $ 3,043,053  
 
           
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009
OVERVIEW
Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs with investor owned utilities, independent power producers, municipalities, and electric cooperatives.
To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR), return on invested capital (ROIC), and net income. EFOR defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). ROIC is focused on earning a return on all invested capital that meets or exceeds Southern Power’s weighted average cost of capital. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(5.6)   (8.3)   $(20.1)   (15.9)
 
Southern Power’s net income for the third quarter 2010 was $61.7 million compared to $67.3 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010, higher operations and maintenance expenses, and higher depreciation and amortization. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs and lower interest expense, net of amounts capitalized.
Southern Power’s net income for year-to-date 2010 was $106.2 million compared to $126.3 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010, higher operations and maintenance expenses, and higher depreciation and amortization. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs, higher tax benefits associated with the construction of Plant Nacogdoches, and lower interest expense, net of amounts capitalized.
Wholesale Revenues Non-Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$128.6   96.6   $250.4   78.6
 
Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market cost of available energy compared to the cost of Southern Power’s energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale energy sales to non-affiliates for the third quarter 2010 were $261.6 million compared to $133.0 million for the corresponding period in 2009. The increase was mainly due to $132.8 million of higher energy and capacity revenues under existing non-affiliate PPAs and new non-affiliate PPAs that began in January, June, and July 2010 and $6.5 million of higher revenues from energy sales that were not covered by PPAs due to more favorable weather in the third quarter 2010 compared to the corresponding period in 2009. These increases were partially offset by $6.9 million of lower energy and capacity revenues associated with the expiration of a non-affiliate PPA in December 2009 and a $3.8 million decrease in revenues from power sales under the IIC.
Wholesale energy sales to non-affiliates for year-to-date 2010 were $568.9 million compared to $318.5 million for the corresponding period in 2009. The increase was mainly due to $220.9 million of higher energy and capacity revenues under existing non-affiliate PPAs and new non-affiliate PPAs that began in January, June, and July 2010. Also contributing to the increase was $65.5 million of higher revenues from energy sales that were not covered by PPAs due to more favorable weather year-to-date 2010 compared to the corresponding period in 2009. These increases were partially offset by $15.4 million of lower energy and capacity revenues associated with the expiration of a non-affiliate PPA in December 2009 and a $20.6 million decrease in revenues from power sales under the IIC.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues Affiliates
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(54.8)   (37.1)   $(133.3)   (31.7)
 
Wholesale energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Wholesale revenues from affiliates for the third quarter 2010 were $93.1 million compared to $147.9 million for the corresponding period in 2009. The decrease was primarily the result of $95.6 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010. The decrease was partially offset by $22.6 million of higher energy and capacity revenues under existing affiliate PPAs and new affiliate PPAs that began in June 2010 and $18.2 million related to increased revenues from power sales under the IIC.
Wholesale revenues from affiliates for year-to-date 2010 were $287.6 million compared to $420.9 million for the corresponding period in 2009. The decrease was primarily the result of $222.6 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in December 2009 and in May 2010. The decrease was partially offset by $36.4 million of higher energy and capacity revenues under existing affiliate PPAs and new affiliate PPAs that began in June 2010 and $52.9 million related to increased revenues from power sales under the IIC.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
                                 
    Third Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Third Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel
  $ 61.7       104.8     $ 118.4       67.1  
Purchased power – non-affiliates
    4.9       24.6       (7.2 )     (10.8 )
Purchased power – affiliates
    10.5       50.4       29.8       59.8  
                     
Total fuel and purchased power expenses
  $ 77.1             $ 141.0          
                     
Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.
In the third quarter 2010, total fuel and purchased power expenses were $176.9 million compared to $99.8 million for the corresponding period in 2009. Total fuel and purchased power expenses increased $43.7 million due to a 21.0% increase in the average cost of natural gas and a 69.1% increase in the average cost of purchased power. Additionally, total fuel and purchased power expenses increased $33.4 million due to an increase in KWHs generated and purchased.
For year-to-date 2010, total fuel and purchased power expenses were $433.6 million compared to $292.6 million for the corresponding period in 2009. Total fuel and purchased power expenses increased $78.0 million due to a 14.2% increase in the average cost of natural gas and a 42.4% increase in the average cost of purchased power. Additionally, total fuel and purchased power expenses increased $63.0 million due to an increase in KWHs generated and purchased.
In the third quarter 2010, fuel expense was $120.5 million compared to $58.8 million for the corresponding period in 2009. Fuel expense increased $20.7 million associated with a 21.0% increase in the average cost of natural gas and $40.9 million due to an increase in KWHs generated.
For year-to-date 2010, fuel expense was $294.7 million compared to $176.3 million for the corresponding period in 2009. Fuel expense increased $36.6 million associated with a 14.2% increase in the average cost of natural gas and $81.7 million due to an increase in KWHs generated.
In the third quarter 2010, purchased power expense was $56.4 million compared to $40.9 million for the corresponding period in 2009. Purchased power expenses increased $23.0 million due to an increase in the average cost of purchased power, partially offset by a $7.5 million decrease due to fewer KWHs purchased.
For year-to-date 2010, purchased power expense was $139.0 million compared to $116.3 million for the corresponding period in 2009. Purchased power expenses increased $41.4 million due to an increase in the average cost of purchased power, partially offset by an $18.7 million decrease due to fewer KWHs purchased.
Other Operations and Maintenance Expenses
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$5.5   19.0   $14.5   14.9
 
In the third quarter 2010, other operations and maintenance expenses were $34.6 million compared to $29.1 million for the corresponding period in 2009. This increase was primarily due to $3.6 million related to generating plant outages and maintenance, $0.5 million associated with a loss on the sale of property, and $0.5 million associated with an increase in information technology costs.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, other operations and maintenance expenses were $111.5 million compared to $97.0 million for the corresponding period in 2009. This increase was primarily due to $4.1 million of additional expense associated with the passage of healthcare legislation in March 2010, $6.9 million related to generating plant outages and maintenance, $0.6 million associated with a loss on the sale of property, $0.5 million associated with an increase in information technology costs, and $1.1 million associated with employee benefits.
See FUTURE EARNINGS POTENTIAL – “Legislation” herein for additional information regarding healthcare legislation.
Depreciation and Amortization
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$6.2   26.6   $12.7   16.9
 
In the third quarter 2010, depreciation and amortization was $29.4 million compared to $23.2 million for the corresponding period in 2009. The increase was primarily related to $1.6 million associated with the acquisition of West Georgia Generating Company LLC (West Georgia) and the divestiture of DeSoto County Generating Company LLC (DeSoto) which resulted in an increase in property, plant, and equipment of approximately $120.2 million. The increase was also due to $1.8 million of equipment retirements, $2.3 million associated with changes in depreciation rates, and $0.5 million related to other increases in property, plant, and equipment.
For year-to-date 2010, depreciation and amortization was $87.4 million compared to $74.7 million for the corresponding period in 2009. The increase was primarily related to $4.8 million associated with the West Georgia/DeSoto acquisition/divestiture described above, $6.6 million of equipment retirements, and $1.2 million related to other increases in property, plant, and equipment.
See Note 1 to the financial statements of Southern Power under “Depreciation” and Note 2 to the financial statements of Southern Power under “West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture” in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.6)   (12.3)   $(6.2)   (9.6)
 
In the third quarter 2010, interest expense, net of amounts capitalized was $18.8 million compared to $21.4 million for the corresponding period in 2009. This decrease was primarily related to $3.1 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.2 million associated with an increase in interest expense on commercial paper and $0.2 million associated with interest rate swaps on senior notes.
For year-to-date 2010, interest expense, net of amounts capitalized was $58.4 million compared to $64.6 million for the corresponding period in 2009. This decrease was primarily related to $7.3 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.5 million associated with an increase in interest expense on commercial paper and $0.5 million associated with interest rate swaps on senior notes.
See FUTURE EARNINGS POTENTIAL – “Construction Projects” herein for additional information.

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Other Income (Expense), Net
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.8)   (104.2)   $(2.3)   (92.0)
 
In the third quarter 2010, other income (expense), net was $(0.1) million compared to $2.7 million for the corresponding period in 2009. For year-to-date 2010, other income (expense), net was $0.2 million compared to $2.5 million for the corresponding period in 2009. These decreases were primarily related to profit recognized in 2009 under a construction contract with the Orlando Utilities Commission (OUC) whereby Southern Power provided engineering, procurement, and construction services to build a combined cycle unit for the OUC.
Income Taxes
             
Third Quarter 2010 vs. Third Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(9.8)   (23.9)   $(28.4)   (36.0)
 
In the third quarter 2010, income taxes were $31.3 million compared to $41.1 million for the corresponding period in 2009. The decrease was primarily due to $5.9 million associated with lower pre-tax earnings, $1.4 million related to an increase in the federal production activities deduction, and $0.8 million of tax benefits associated with the construction of Plant Nacogdoches.
For year-to-date 2010, income taxes were $50.6 million compared to $79.0 million for the corresponding period in 2009. The decrease was primarily due to $19.0 million associated with lower pre-tax earnings, $5.9 million of tax benefits associated with the construction of Plant Nacogdoches, and $1.8 million related to an increase in the federal production activities deduction.
See Note 1 to the financial statements of Southern Power under “Convertible Investment Tax Credits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs. The level of future earnings also depends on numerous factors including regulatory matters, creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. 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 Power in Item 7 of the Form 10-K.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also affect earnings. While Southern Power’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.
Air Quality
On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO2) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas in which Southern Power operates generating assets are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO2 standard could result in significant additional compliance and operational costs for units that require new source permitting.
Carbon Dioxide Litigation
Other Litigation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations” of Southern Power in Item 7 of the Form 10-K for information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and 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 Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect results of operations, cash flows, and financial condition. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.
Legislation
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Income Tax Matters - Legislation” of Southern Power in Item 7 of the Form 10-K for additional information. On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date. Southern Power incurred a non-cash write-off of approximately $4 million to expense for the nine months ended September 30, 2010. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Southern Power cannot be determined at this time.
Income Tax Matters
Tax Method of Accounting for Repairs
Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $5 million for Southern Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Bonus Depreciation
On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Southern Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $3 million.
Construction Projects
Cleveland County Units 1-4
In December 2008, Southern Power announced that it would build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total capacity of 720 MWs. The units are expected to go into commercial operation in 2012. Costs incurred through September 30, 2010 were $138.6 million. The total estimated construction cost is expected to be between $350 million and $400 million.
Nacogdoches
In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through September 30, 2010 were $211.8 million. The total estimated cost of the project is expected to be between $475 million and $500 million.
Power Sales Agreements
On October 15, 2010, Southern Power signed contract extensions with 10 Georgia Electric Membership Corporations (EMCs). These contracts are an extension of requirements service under agreements that were signed in 2008. The extensions have a requirements term of 10 years beginning in 2015 for eight EMCs, 10 years beginning in 2018 for one EMC, and seven years beginning in 2018 for one EMC. The EMCs are projected to purchase an incremental 625 MWs of capacity over the terms of the extensions.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such potential litigation against Southern Power 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 Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from any such proceedings would have a material adverse effect on Southern Power’s financial statements.
See Note (B) to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power 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 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 Southern 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 Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power’s critical accounting policies and estimates related to Revenue Recognition, Percentage of Completion, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Contingent Obligations, Depreciation, and Convertible Investment Tax Credits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power’s financial condition remained stable at September 30, 2010. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See “Sources of Capital” herein for additional information on lines of credit.
Net cash provided from operating activities totaled $255.8 million for the first nine months of 2010, compared to $232.8 million for the corresponding period in 2009. The $23.0 million increase was mainly due to an increase in convertible investment tax credits. Net cash used for investing activities totaled $206.8 million for the first nine months of 2010, compared to $67.0 million for the corresponding period in 2009. The $139.8 million increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $56.2 million for the first nine months of 2010, compared to $77.5 million for the corresponding period in 2009. The decrease in cash used for financing activities was primarily due to an increase in short-term borrowings in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant asset changes in the balance sheet for the first nine months of 2010 include an increase in customer accounts receivable due to seasonality and new PPAs that began in January, June, and July 2010, and an increase in construction work in progress due to Cleveland County and Nacogdoches construction activities.
Significant liability and stockholder’s equity changes in the balance sheet for the first nine months of 2010 include an increase in notes payable mainly related to Cleveland County and Nacogdoches construction activities and an increase in deferred convertible investment tax credits associated with the construction of Plant Nacogdoches.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; new regulatory requirements for generating plants; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Southern Power may use operating cash flows, external funds, equity capital, or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at September 30, 2010 committed credit arrangements with banks of $400 million, all of which expire in 2012. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern 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. Southern Power’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At September 30, 2010, Southern Power had $139 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the third quarter 2010, Southern Power had an average of $186 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $259 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Southern 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 Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $355 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.1 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 Southern Power’s ability to access capital markets, particularly the short-term debt market.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, through the acquisition of Plant Rowan, Southern Power assumed PPAs with Duke Energy and North Carolina Municipal Power Agency No. 1 (NCMPA1) that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power’s credit. The Duke Energy PPA defines the downgrade to be below BBB- or Baa3. The NCMPA1 PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade for both PPAs.
Market Price Risk
Southern Power is exposed to market risks, including changes in interest rates and certain energy-related commodity prices and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and hedging practices. It is Southern Power’s policy that derivatives be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.
Southern Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Because energy from Southern Power’s facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2010 were as follows:
                 
    Third Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (1.2 )   $ (3.5 )
Contracts realized or settled
    3.3       3.8  
Current period changes(a)
    (4.1 )     (2.3 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (2.0 )   $ (2.0 )
 
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The changes in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 were a decrease of $0.8 million and an increase of $1.5 million, respectively, which is due to both power and natural gas positions. This change is attributable to both the volume and prices of power and natural gas as follows:
                         
    September 30,   June 30,   December 31,
    2010   2010   2009
 
Power (net sold)
                       
 
MWHs (in millions)
    0.7       0.7       2.7  
Weighted average contract cost per MWH above (below) market prices (in dollars)
  $ 5.22     $ 6.77     $ (0.36 )
 
Natural gas (net purchase)
                       
 
Commodity – million mmBtu
    9.3       5.6       8.3  
Location basis – million mmBtu
                2.0  
 
Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)
  $ 0.69     $ 1.31     $ 0.29  
 
Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)
  $     $     $ (0.04 )
 
The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
                 
    September 30,   December 31,
Asset (Liability) Derivatives   2010   2009
    (in millions)
Cash flow hedges
  $ 1.5     $ (2.5 )
Not designated
    (3.5 )     (1.0 )
 
Total fair value
  $ (2.0 )   $ (3.5 )
 
Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales 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 as hedges are recognized in the statements of income as incurred.
Total net unrealized pre-tax gains (losses) recognized in income for the three and nine months ended September 30, 2010 for energy-related derivative contracts that are not hedges were $(3.7) million and $(2.4) million, respectively, and will continue to be marked to market until the settlement date. For the three and nine months ended September 30, 2009, the total net unrealized pre-tax gains (losses) recognized in the statements of income were $2 million and $1 million, respectively.
Southern 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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:
                                 
    September 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
            (in millions)        
Level 1
  $     $     $     $  
Level 2
    (2.0 )     (1.3 )     (1.0 )     0.3  
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (2.0 )   $ (1.3 )   $ (1.0 )   $ 0.3  
 

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Power in Item 7 and Note 1 under “Financial Instruments” and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
Southern Power did not issue or redeem any long-term securities during the nine months ended September 30, 2010.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT
     
Registrant
  Applicable Notes
 
   
Southern Company
  A, B, C, D, E, F, G, H, I
 
   
Alabama Power
  A, B, C, E, F, G, H
 
   
Georgia Power
  A, B, C, E, F, G, H
 
   
Gulf Power
  A, B, C, E, F, G, H
 
   
Mississippi Power
  A, B, C, E, F, G, H
 
   
Southern Power
  A, B, C, E, G, H

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
  (A)   INTRODUCTION
      The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2009 have been derived from the audited financial statements of each registrant. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2010 and 2009. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
 
      Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.
 
      Affiliate Transactions
 
      In January 2010, Gulf Power purchased turbine rotor assembly parts owned by Georgia Power and Southern Power for approximately $4 million and $6 million, respectively. In June 2010, Mississippi Power purchased a turbine rotor assembly part from Gulf Power for approximately $6 million. In September 2010, Georgia Power purchased a compressor rotor assembly part owned by Gulf Power for approximately $4 million. In September 2010, Southern Power purchased turbine rotor assembly parts owned by Georgia Power, Gulf Power, and Mississippi Power for approximately $6 million, $1 million, and $7 million, respectively. These affiliate transactions were in accordance with FERC and state PSC rules and guidelines.
      Variable Interest Entities
 
      Effective January 1, 2010, the traditional operating companies and Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the traditional operating companies or Southern Power consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs.
 
      Mississippi Power is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC (Liberty Fuels) in conjunction with the construction of Kemper IGCC described in Note (B) under “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein. Liberty Fuels qualifies as a VIE for which Mississippi Power is the primary beneficiary. As of September 30, 2010, Liberty Fuels has not had a material impact on the financial position and results of operations of Mississippi Power.

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      Southern Power has certain wholly-owned subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
  (B)   CONTINGENCIES AND REGULATORY MATTERS
      See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
 
      General Litigation Matters
 
      Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the registrants and any of their subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant 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 such registrant’s financial statements.
 
      Mirant Matters
 
      Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
 
      In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).
 
      Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for certain costs. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. If Southern Company’s claims for indemnification with respect to these costs are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. As a result of the $202 million settlement in March 2009 of another suit related to Mirant (MC Asset Recovery litigation), the maximum amount Southern Company can assert by proof of claim in the Mirant bankruptcy is capped at $9.5 million. See Note 5 to the financial statements of Southern Company under “Effective Tax Rate” in Item 8 of the Form 10-K for more information regarding the MC Asset Recovery litigation settlement. By settlement agreement, dated as of July 7, 2010, substantially all the claims filed by Southern Company against Mirant have been resolved. Pursuant to the agreement, Southern Company was given allowed unsecured claims against Mirant in the aggregate amount of approximately $8.8 million, which claims will be treated pursuant to the terms of the Mirant plan of reorganization. The parties also released each other from any other claims arising from events or conduct prior to the effective date of Mirant’s plan of reorganization, with certain limited exceptions. The settlement has been approved by the bankruptcy court. This matter is now concluded.

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      Environmental Matters
 
      New Source Review Actions
 
      In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.
 
      In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting.
 
      On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to the facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims.
 
      Southern Company and the traditional operating companies believe that they complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates; however, the ultimate outcome of this matter cannot now be determined.
 
      Carbon Dioxide Litigation
 
      New York Case
 
      In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the

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      dismissal of the plaintiffs’ claim, and remanding the case to the district court. In November 2009, the defendants, including Southern Company, sought rehearing en banc. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.
 
      Kivalina Case
 
      In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.
 
      Other Litigation
 
      Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, in October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. Southern Company is not currently a party to this litigation, but the traditional operating companies and Southern Power were named as defendants in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.
 
      Environmental Remediation
 
      The registrants must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the subsidiaries may also incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.
 
      Georgia Power’s environmental remediation liability as of September 30, 2010 was $13.8 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous

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      Sites Inventory and CERCLA NPL are anticipated; however, they are not expected to have a material impact on Georgia Power’s financial statements.
 
      By letter dated September 30, 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Georgia Power’s financial statements.
 
      Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $62.2 million as of September 30, 2010. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.
 
      In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.
 
      The final outcome of these matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, Southern Company, Georgia Power, Gulf Power, and Mississippi Power do not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
 
      FERC Matters
 
      Market-Based Rate Authority
 
      Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
 
      In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.
 
      In December 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that any subsidiary of Southern Company possesses or has exercised any market power. The agreement likewise does not require Southern Company to make any refunds related to sales during the 15-month refund period. The agreement does provide for the traditional operating companies and Southern Power to donate a total of $1.7 million to nonprofit organizations in the states in which they operate for the purpose of offsetting the electricity bills of low-income retail customers. The joint offer of settlement

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      was filed on March 2, 2010. On July 13, 2010, the FERC issued an order approving the filed settlement, finding it to be fair, reasonable, and in the public interest. The traditional operating companies and Southern Power made the related donations. This matter is now concluded.
 
      Intercompany Interchange Contract
 
      Southern Company’s generation fleet in its retail service territory is operated under the Intercompany Interchange Contract (IIC), as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the Power Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.
 
      In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms. Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on Southern Company’s or the traditional operating companies’ financial statements. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.
 
      Right of Way Litigation
 
      Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.
 
      Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.
 
      In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. On August 24, 2010, the defendants filed a motion to dismiss the suit. The plaintiff has opposed this motion. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the

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      right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.
 
      Nuclear Fuel Disposal Cost Litigation
 
      See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel. In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.
 
      In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of September 30, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.
 
      Income Tax Matters
 
      Georgia State Income Tax Credits
 
      Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s or Georgia Power’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s and Georgia Power’s cash flow. See Note 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Unrecognized Tax Benefits” and Note (G) herein for additional information. The ultimate outcome of this matter cannot now be determined.
 
      Tax Method of Accounting for Repairs
 
      Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $117 million for Alabama Power, $110 million for Georgia Power, $6 million for Gulf Power, $3 million for Mississippi Power, $5 million for Southern Power, and $243 million for Southern Company on a consolidated basis. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

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      Bonus Depreciation
 
      On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. The estimated cash flow reduction to tax payments for 2010 are approximately $102 million for Alabama Power, $130 million for Georgia Power, $37 million for Gulf Power, $16 million for Mississippi Power, $3 million for Southern Power, and $309 million for Southern Company on a consolidated basis.
 
      State PSC Matters
 
      Alabama Power
 
      Nuclear Outage Accounting Order
 
      On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.
 
      The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.
 
      Natural Disaster Cost Recovery
 
      See Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery.
 
      Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities, referred to as the NDR.
 
      On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
 
      The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.

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      In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.
 
      Georgia Power
 
      Rate Plans
 
      See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” and of Southern Company under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” and “– Cost of Removal” in Item 8 of the Form 10-K for information regarding the 2007 Retail Rate Plan.
 
      On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.
 
      In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1, 2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.
 
      Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:
  §   Continuation of a plus or minus 100 basis point range for ROE.
 
  §   Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
 
      The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.

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  §   Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
 
  §   Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
 
  §   Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.
      These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.
 
      Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.
 
      The final outcome of these matters cannot now be determined.
 
      Fuel Cost Recovery
 
      See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” and of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information on Georgia Power’s fuel cost recovery.
 
      On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.
 
      Nuclear Construction
 
      See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Construction – Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of two additional nuclear generating units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4).

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      In June 2009, the Southern Alliance for Clean Energy (SACE) 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 Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. The dismissal of the claim related to the Georgia Nuclear Energy Financing Act is subject to appeal and the plaintiffs are expected to re-file this claim in the future. In addition, on May 5, 2010, the court issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, the SACE and the Fulton County Taxpayers Foundation, Inc. filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The SACE subsequently appealed to the Superior Court of Fulton County.
 
      In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors in response to 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.
 
      On August 17, 2010, the Georgia PSC voted to approve Georgia Power’s semi-annual construction monitoring report including all construction and capital costs of $583 million made on Plant Vogtle Units 3 and 4 through December 31, 2009. The Georgia PSC also approved an amendment to the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 that replaced certain index-based adjustments with fixed escalation factors. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
 
      On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4, effective January 1, 2011.
 
      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 be determined at this time.
 
      Other
 
      In August 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. In September 2009, Georgia Power amended the report. As amended, the report included a request for an increase in the certified costs to construct Plant McDonough. On February 24, 2010, Georgia Power reached a stipulation agreement with the Georgia PSC staff that was approved by the Georgia PSC on March 16, 2010. The stipulation resolved the June 30, 2009 construction monitoring report, including the approval of actual expenditures and the requested increase in the certified amount.
 
      On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. In addition, on September 7, 2010, the Georgia PSC approved the March 31, 2010 construction monitoring report including actual project expenditures incurred through March 31, 2010.
 
      On September 21, 2010, the Georgia PSC approved Georgia Power’s offer to place 562 MWs of wholesale capacity into retail rate base. A portion of the capacity will go into retail rate base in January 2015, with the remainder going into retail rate base starting April 1, 2016.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Mississippi Power
 
      Integrated Coal Gasification Combined Cycle
 
      See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle (IGCC)” and of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding Mississippi Power’s construction of the Kemper IGCC.
 
      On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the Kemper IGCC, which modifies the original PSD air permit issued in October 2008. The Mississippi Chapter of the Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit.
 
      In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. On September 30, 2010, Mississippi Power and the IRS executed the closing agreement for the Phase II tax credits. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits. In order to remain eligible for the Phase II tax credits, Mississippi Power must capture and sequester at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits, and must meet the required in-service date, satisfy environmental and other permitting requirements, and have in place a binding contract for the steam turbine generator.
 
      On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the Kemper IGCC did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power. The April 2010 order also approved recovery of $46 million of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of SCS, which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million has been incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010 will be reviewed and addressed in a future proceeding.
 
      On May 10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order.
 
      On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved the alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the State of Mississippi Baseload Act of 2008 (Baseload Act), which provides for the accrual of allowance for funds used during construction in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi

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      Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.
 
      In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and will acquire mineral reserves located at the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation.
 
      On June 17, 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant a certificate of public convenience and necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by Mississippi Power on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied Mississippi Power’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court.
 
      On July 27, 2010, Mississippi Power and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.
 
      On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the Clean Coal Power Initiative Round 2 (CCPI2) grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for Mississippi Power to receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during the initial operation of the Kemper IGCC.
 
      As of September 30, 2010, Mississippi Power had spent a total of $195.5 million on the Kemper IGCC, including regulatory filing costs. Of this total, $156.4 million was included in CWIP (net of $24.8 million recorded as a receivable of CCPI2 grant funds), $11.5 million was recorded in other regulatory assets, $1.3 million was recorded in other deferred charges and assets, and $1.5 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed.
 
      The ultimate outcome of these matters cannot now be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
  (C)   FAIR VALUE MEASUREMENTS
      As of September 30, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
                                 
    Fair Value Measurements Using    
    Quoted Prices            
    in Active   Significant        
    Markets for   Other   Significant    
    Identical   Observable   Unobservable    
    Assets   Inputs   Inputs    
As of September 30, 2010:   (Level 1)   (Level 2)   (Level 3)   Total
    (in millions)
Southern Company
                               
Assets:
                               
Energy-related derivatives
  $     $ 8     $     $ 8  
Interest rate derivatives
          17             17  
Foreign currency derivatives
          5             5  
Nuclear decommissioning trusts(a)(b)
    758       390             1,148  
Cash equivalents and restricted cash
    1,082                   1,082  
Other investments
    21       51       13       85  
 
Total
  $ 1,861     $ 471     $ 13     $ 2,345  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 256     $     $ 256  
Interest rate derivatives
          2             2  
 
Total
  $     $ 258     $     $ 258  
 
 
                               
Alabama Power
                               
Assets:
                               
Nuclear decommissioning trusts:(a)
                               
Domestic equity
  $ 304     $ 55     $     $ 359  
U.S. Treasury and government agency securities
    20       8             28  
Corporate bonds
          86             86  
Mortgage and asset backed securities
          32             32  
Other
          10             10  
Cash equivalents and restricted cash
    319                   319  
 
Total
  $ 643     $ 191     $     $ 834  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 54     $     $ 54  
 

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
                                 
    Fair Value Measurements Using        
    Quoted Prices            
    in Active   Significant        
    Markets for   Other   Significant    
    Identical   Observable   Unobservable    
    Assets   Inputs   Inputs    
As of September 30, 2010:   (Level 1)   (Level 2)   (Level 3)   Total
    (in millions)
Georgia Power
                               
Assets:
                               
Nuclear decommissioning trusts:(a)
                               
Domestic equity
  $ 434     $ 1     $     $ 435  
U.S. Treasury and government agency securities
          26             26  
Municipal bonds
          38             38  
Corporate bonds
          76             76  
Mortgage and asset backed securities
          41             41  
Other
          17             17  
Cash equivalents
    574                   574  
 
Total
  $ 1,008     $ 199     $     $ 1,207  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 121     $     $ 121  
 
 
                               
Gulf Power
                               
Assets:
                               
Cash equivalents
  $ 12     $     $     $ 12  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 18     $     $ 18  
 
 
                               
Mississippi Power
                               
Assets:
                               
Foreign currency derivatives
  $     $ 5     $     $ 5  
Cash equivalents
    125                   125  
 
Total
  $ 125     $ 5     $     $ 130  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 54     $     $ 54  
 
 
                               
Southern Power
                               
Assets:
                               
Energy-related derivatives
  $     $ 7     $     $ 7  
 
Liabilities:
                               
Energy-related derivatives
  $     $ 9     $     $ 9  
 
 
(a)   Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
(b)   For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
      Valuation Methodologies
 
      The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

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      “Other investments” include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.
 
      For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and significant unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.
 
      A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available.
      As of September 30, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
                                             
    Fair   Unfunded   Redemption   Redemption
As of September 30, 2010:   Value   Commitments   Frequency   Notice Period
    (in millions)                        
Southern Company
                               
Nuclear decommissioning trusts:
                               
Corporate bonds – commingled funds
  $ 35     None   Daily     1 to 3 days  
Other – commingled funds
    17     None   Daily   Not applicable
Trust owned life insurance
    81     None   Daily   15 days
Cash equivalents and restricted cash:
                               
Money market funds
    1,082     None   Daily   Not applicable
Other:
                               
Deferred compensation – money market funds
    1     None   Daily   Not applicable
 
 
                               
Alabama Power
                               
Nuclear decommissioning trusts:
                               
Trust owned life insurance
  $ 81     None   Daily   15 days
Cash equivalents and restricted cash:
                               
Money market funds
    319     None   Daily   Not applicable
 
 
                               
Georgia Power
                               
Nuclear decommissioning trusts:
                               
Corporate bonds – commingled funds
  $ 35     None   Daily     1 to 3 days  
Other – commingled funds
    17     None   Daily   Not applicable
Cash equivalents:
                               
Money market funds
    574     None   Daily   Not applicable
 
 
                               
Gulf Power
                               
Cash equivalents:
                               
Money market funds
  $ 12     None   Daily   Not applicable
 
 
                               
Mississippi Power
                               
Cash equivalents:
                               
Money market funds
  $ 125     None   Daily   Not applicable
 

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      The commingled funds in the nuclear decommissioning trusts invest primarily in a diversified portfolio of investment high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity.
 
      Alabama Power’s nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the tables above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.
 
      Southern Company, Alabama Power, and Georgia Power account for investment securities held in the nuclear decommissioning trust funds at fair value. For the three months and nine months ended September 30, 2010, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $43 million and $27 million, respectively, for Alabama Power, $51 million and $25 million, respectively, for Georgia Power, and $94 million and $52 million, respectively, for Southern Company.
 
      The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investments in the money market funds.
      Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at September 30, 2010 were as follows:
                       
    Level 3
    Other
    Three Months Ended   Nine Months Ended
    September 30, 2010   September 30, 2010
    (in millions)
Beginning balance
  $ 19     $ 35  
Total gains (losses) — realized/unrealized:
               
Included in earnings
    (1 )     (1 )
Included in OCI
    (5 )     (1 )
Transfers out of Level 3
          (20 )
 
Ending balance at September 30, 2010
  $ 13     $ 13  
 
      Transfers in and out of the levels of fair value hierarchy are recognized as of the end of the reporting period. At March 31, 2010, the value of one of the investments was reclassified from Level 3 to Level 1 because the securities began trading on the public market. The reclassification is reflected in the table above as a transfer out of Level 3 at its fair value.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      At September 30, 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:
                 
    Carrying Amount   Fair Value
    (in millions)
Long-term debt:
               
Southern Company
  $ 20,089     $ 21,479  
Alabama Power
  $ 6,183     $ 6,679  
Georgia Power
  $ 8,800     $ 9,371  
Gulf Power
  $ 1,297     $ 1,386  
Mississippi Power
  $ 617     $ 657  
Southern Power
  $ 1,298     $ 1,424  
      The fair values were based on closing market prices (Level 1) or closing prices of comparable instruments (Level 2).
  (D)   STOCKHOLDERS’ EQUITY
      Earnings per Share
 
      For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to exercised options and outstanding options under the stock option plan. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for further information on the stock option plan. The effect of the stock options was determined using the treasury stock method.
      Shares used to compute diluted earnings per share were as follows:
                                                      
    Three Months   Three Months   Nine Months   Nine Months
    Ended   Ended   Ended   Ended
    September 30, 2010   September 30, 2009   September 30, 2010   September 30, 2009
    (in thousands)
As reported shares
    835,953       798,418       828,947       789,675  
Effect of options
    5,882       1,760       4,273       1,584  
     
Diluted shares
    841,835       800,178       833,220       791,259  
     
      Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 6.7 million and 25.5 million for the three months ended September 30, 2010 and 2009, respectively, and 13.7 million and 37.7 million for the nine months ended September 30, 2010 and 2009, respectively. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options would have increased by 0.4 million and 2.2 million shares for the three months ended September 30, 2010 and 2009, respectively, and 0.8 million and 3.3 million shares for the nine months ended September 30, 2010 and 2009, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Changes in Stockholders’ Equity
      The following table presents year-to-date changes in stockholders’ equity of Southern Company:
                                         
                            Preferred and    
    Number of   Common   Preference   Total
    Common Shares   Stockholders’   Stock of   Stockholders’
    Issued   Treasury   Equity   Subsidiaries   Equity
    (in thousands)   (in millions)
Balance at December 31, 2009
    820,152       (505 )   $ 14,878     $ 707     $ 15,585  
Net income after dividends on preferred and preference stock
                1,822             1,822  
Other comprehensive income (loss)
                16             16  
Stock issued
    18,994             650             650  
Cash dividends on common stock
                (1,114 )           (1,114 )
Other
          30       3             3  
 
Balance at September 30, 2010
    839,146       (475 )   $ 16,255     $ 707     $ 16,962  
 
 
                                       
Balance at December 31, 2008
    777,616       (424 )   $ 13,276     $ 707     $ 13,983  
Net income after dividends on preferred and preference stock
                1,394             1,394  
Other comprehensive income (loss)
                20             20  
Stock issued
    23,078             692             692  
Cash dividends on common stock
                (1,018 )           (1,018 )
Other
          (58 )     (2 )           (2 )
 
Balance at September 30, 2009
    800,694       (482 )   $ 14,362     $ 707     $ 15,069  
 
  (E)   FINANCING
      Bank Credit Arrangements
 
      Bank credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.
      The following table outlines the credit arrangements by company as of September 30, 2010:
                                                                         
                    Executable                           Expires Within One
                    Term-Loans   Expires   Year(a)
                                                                    No
                    One   Two                           Term   Term
Company   Total   Unused   Year   Years   2010   2011   2012   Out   Out
    (in millions)          
Southern Company
  $ 950     $ 950     $     $     $     $     $ 950     $     $  
Alabama Power
    1,271       1,271       372             60       446       765       372       134  
Georgia Power
    1,715       1,703       220       40             595       1,120       260       335  
Gulf Power
    235       235       205             50       185             205       30  
Mississippi Power
    161       161       65       41       16       145             106       55  
Southern Power
    400       400                               400              
Other
    60       60       60                   60             60        
 
Total
  $ 4,792     $ 4,780     $ 922     $ 81     $ 126     $ 1,431     $ 3,235     $ 1,003     $ 554  
 
 
(a)   Reflects facilities expiring on or before September 30, 2011.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011.
  (F)   RETIREMENT BENEFITS
      Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related trusts to the extent required by their respective regulatory commissions.
 
      See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K.
      Components of the net periodic benefit costs for the three and nine months ended September 30, 2010 and 2009 were as follows:
                                         
    Southern   Alabama   Georgia   Gulf   Mississippi
PENSION PLANS   Company   Power   Power   Power   Power
 
    (in millions)
Three Months Ended September 30, 2010
                                       
Service cost
  $ 43     $ 10     $ 13     $ 2     $ 2  
Interest cost
    98       25       36       5       4  
Expected return on plan assets
    (138 )     (42 )     (54 )     (6 )     (5 )
Net amortization
    11       3       4             1  
 
Net cost (income)
  $ 14     $ (4 )   $ (1 )   $ 1     $ 2  
 
 
                                       
Nine Months Ended September 30, 2010
                                       
Service cost
  $ 129     $ 31     $ 40     $ 6     $ 6  
Interest cost
    293       73       109       13       13  
Expected return on plan assets
    (413 )     (126 )     (164 )     (18 )     (16 )
Net amortization
    32       8       11       1       2  
 
Net cost (income)
  $ 41     $ (14 )   $ (4 )   $ 2     $ 5  
 
 
                                       
Three Months Ended September 30, 2009
                                       
Service cost
  $ 36     $ 8     $ 12     $ 2     $ 2  
Interest cost
    96       24       37       4       4  
Expected return on plan assets
    (135 )     (41 )     (54 )     (6 )     (6 )
Net amortization
    11       3       4       1       1  
 
Net cost (income)
  $ 8     $ (6 )   $ (1 )   $ 1     $ 1  
 
 
                                       
Nine Months Ended September 30, 2009
                                       
Service cost
  $ 109     $ 25     $ 36     $ 5     $ 5  
Interest cost
    290       72       110       13       13  
Expected return on plan assets
    (406 )     (123 )     (162 )     (18 )     (16 )
Net amortization
    32       8       12       1       2  
 
Net cost (income)
  $ 25     $ (18 )   $ (4 )   $ 1     $ 4  
 

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
                                         
    Southern   Alabama   Georgia   Gulf   Mississippi
POSTRETIREMENT BENEFITS   Company   Power   Power   Power   Power
 
    (in millions)
Three Months Ended September 30, 2010
                                       
Service cost
  $ 6     $ 2     $ 3     $     $  
Interest cost
    25       7       11       1       2  
Expected return on plan assets
    (15 )     (7 )     (8 )            
Net amortization
    5       2       2              
 
Net cost (income)
  $ 21     $ 4     $ 8     $ 1     $ 2  
 
 
                                       
Nine Months Ended September 30, 2010
                                       
Service cost
  $ 19     $ 5     $ 7     $ 1     $ 1  
Interest cost
    75       20       33       3       4  
Expected return on plan assets
    (47 )     (19 )     (23 )     (1 )     (1 )
Net amortization
    15       5       8              
 
Net cost (income)
  $ 62     $ 11     $ 25     $ 3     $ 4  
 
 
                                       
Three Months Ended September 30, 2009
                                       
Service cost
  $ 7     $ 2     $ 2     $     $  
Interest cost
    28       7       13       1       1  
Expected return on plan assets
    (16 )     (6 )     (8 )            
Net amortization
    7       2       4             1  
 
Net cost (income)
  $ 26     $ 5     $ 11     $ 1     $ 2  
 
 
                                       
Nine Months Ended September 30, 2009
                                       
Service cost
  $ 20     $ 5     $ 7     $ 1     $ 1  
Interest cost
    85       22       38       4       4  
Expected return on plan assets
    (46 )     (18 )     (23 )     (1 )     (1 )
Net amortization
    21       6       11             1  
 
Net cost (income)
  $ 80     $ 15     $ 33     $ 4     $ 5  
 
  (G)   EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
      Effective Tax Rate
 
      Southern Company’s effective tax rate was 33.1% for the nine months ended September 30, 2010, as compared to 36.5% for the corresponding period in 2009. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock plans dividend deduction and AFUDC equity, which is not taxable. See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate. Southern Company’s effective tax rate decreased for the nine months ended September 30, 2010 as compared to September 30, 2009 primarily due to the $202 million charge for the MC Asset Recovery settlement, which occurred in the first quarter 2009. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. Additionally, Georgia Power’s effective tax rate decreased for the nine months ended September 30, 2010 compared to September 30, 2009 from 34.7% to 32.3% primarily due to the recognition of additional Georgia state tax credits and additional AFUDC equity. Southern Power’s effective tax rate decreased for the nine months ended September 30, 2010 compared to September 30, 2009 from 38.5% to 32.3% primarily due to tax benefits associated with the construction of its biomass facility.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Unrecognized Tax Benefits
      Changes during 2010 for unrecognized tax benefits were as follows:
                                                 
    Southern   Alabama   Georgia   Gulf   Mississippi   Southern
    Company   Power   Power   Power   Power   Power
 
    (in millions)
Unrecognized tax benefits as of December 31, 2009
  $ 199     $ 6     $ 181     $ 2     $ 3     $  
Tax positions from current periods
    37       1       35                   1  
Tax position increases from prior periods
    67       31       32       1             1  
Tax position decreases from prior periods
    (32 )           (28 )                  
Reductions due to expired statute of limitations
                                   
 
Balance as of September 30, 2010
  $ 271     $ 38     $ 220     $ 3     $ 3     $ 2  
 
The tax positions increase from current periods relates primarily to the Georgia state tax credits litigation and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions. The tax position decrease from prior periods relates primarily to the Georgia state tax credits litigation. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” herein for additional information.
The impact on Southern Company’s effective tax rate, if recognized, was as follows:
                                 
                            As of
                            December 31,
    As of September 30, 2010   2009
    Georgia       Southern   Southern
    Power   Other   Company   Company
 
    (in millions)
Tax positions impacting the effective tax rate
  $ 191     $ 15     $ 206     $ 199  
Tax positions not impacting the effective tax rate
    29       36       65        
 
Balance of unrecognized tax benefits
  $ 220     $ 51     $ 271     $ 199  
 
      The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” herein for additional information.
      Accrued interest for unrecognized tax benefits was as follows:
                         
    Georgia   Other   Southern
    Power   Registrants   Company
 
    (in millions)
Interest accrued as of December 31, 2009
  $ 20     $ 1     $ 21  
Interest reclassified due to settlements
                 
Interest accrued during the period
    5       1       6  
 
Balance as of September 30, 2010
  $ 25     $ 2     $ 27  
 
      None of the registrants accrued any penalties on uncertain tax positions.
 
      It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
  (H)   DERIVATIVES
      Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.
      Energy-Related Derivatives
 
      The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.
 
      To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
 
      Energy-related derivative contracts are accounted for in one of three methods:
    Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
 
    Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges, which are mainly used by Southern Power, to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
 
    Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
      Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      At September 30, 2010, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
                                                 
    Power   Gas
            Longest   Longest   Net   Longest   Longest
    Net Sold   Hedge   Non-Hedge   Purchased   Hedge   Non-Hedge
As of September 30, 2010:   MWH   Date   Date   mmBtu   Date   Date
 
 
  (in millions)                   (in millions)                
Southern Company
    0.7       2010       2011       138       2014       2014  
Alabama Power
                      34       2014        
Georgia Power
                      61       2014        
Gulf Power
                      14       2014        
Mississippi Power
                      20       2014        
Southern Power
    0.7       2010       2011       9       2012       2014  
 
      In addition to the volumes discussed in the table above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 5 million mmBtu for Southern Company, 3 million mmBtu for Georgia Power, and less than 1 million mmBtu for each of the other registrants.
 
      For the next 12-month period ending September 30, 2011, Southern Company and Southern Power expect to reclassify $5 million in gains from OCI to revenue and $2 million in losses from OCI to fuel expense with respect to cash flow hedges. Such amounts are immaterial for all other registrants.
 
      Interest Rate Derivatives
 
      Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. Derivatives related to existing fixed rate securities are accounted for as fair value hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
 
      For cash flow hedges, the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. For fair value hedges, the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness.
      At September 30, 2010, the following interest rate derivatives were outstanding:
                                         
                                Fair Value
                        Hedge   Gain (Loss)
    Notional   Interest Rate   Interest Rate   Maturity   September 30,
    Amount   Received   Paid   Date   2010
 
 
  (in millions)                       (in millions)
Cash flow hedges of existing debt
                                   
Southern Company
  $ 300   3-month LIBOR +
0.40% spread
  1.24 %*   October 2011   $ (2 )
Fair value hedges of existing debt
                                   
Southern Company
    350   4.15%   3-month LIBOR +
1.96%* spread
  May 2014     17  
                         
Total
  $ 650                         $ 15  
                         
*   Weighted Average

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2011, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.
                 
    Estimated Gain (Loss) to    
    be Reclassified for the   Total Deferred
    12 Months Ending   Gains (Losses)
Registrant   September 30, 2011   Amortized Through
 
 
  (in millions)
       
Southern Company
  $ (18 )     2037  
Alabama Power
    1       2035  
Georgia Power
    (5 )     2037  
Gulf Power
    (1 )     2020  
Southern Power
    (11 )     2016  
 
      Foreign Currency Derivatives
 
      Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
      At September 30, 2010, the following foreign currency derivatives were outstanding:
                                             
                            Fair Value
                        Gain (Loss)
    Notional           Hedge   September 30,
    Amount   Forward Rate   Maturity Date   2010
 
 
  (in millions)                   (in millions)
Cash flow hedges of forecasted transactions
                               
Southern Company
  YEN780   85.45 Yen per
Dollar*
  Various through May 2011   $  
Fair value hedges of firm commitments
                               
Mississippi Power
  EUR36.7   1.228 Dollars per
Euro*
  Various through June 2012     5  
                             
Total
                          $ 5  
                             
*   Weighted Average

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Derivative Financial Statement Presentation and Amounts
      At September 30, 2010, the fair value of energy-related derivatives, interest rate derivatives and foreign currency derivatives were reflected in the balance sheets as follows:
                                                 
Asset Derivatives at September 30, 2010
    Fair Value
Derivative Category and Balance Sheet   Southern   Alabama   Georgia   Gulf   Mississippi   Southern
Location   Company   Power   Power   Power   Power   Power
 
    (in millions)
Derivatives designated as hedging instruments in cash flow and fair value hedges
                                               
Energy-related derivatives:
                                               
Other current assets*
  $ 5     $     $     $     $     $  
Assets from risk management activities
                                  5  
Interest rate derivatives:
                                               
Other current assets
    7                                
Other deferred charges and assets
    10                                
Foreign currency derivatives:
                                               
Other current assets
    3                         3        
Other deferred charges and assets
    2                         2        
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges
  $ 27     $     $     $     $ 5     $ 5  
 
 
                                               
Derivatives not designated as hedging instruments
                                               
Energy-related derivatives:
                                               
Other current assets*
  $ 2     $     $     $     $     $  
Assets from risk management activities
                                  2  
Other deferred charges and assets
    1                                
 
Total derivatives not designated as hedging instruments
  $ 3     $     $     $     $     $ 2  
 
 
                                               
Total asset derivatives
  $ 30     $     $     $     $ 5     $ 7  
 
*   Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
                                                 
Liability Derivatives at September 30, 2010
    Fair Value
Derivative Category and Balance Sheet   Southern   Alabama   Georgia   Gulf   Mississippi   Southern
Location   Company   Power   Power   Power   Power   Power
 
    (in millions)
Derivatives designated as hedging instruments for regulatory purposes
                                               
Energy-related derivatives:
                                               
Liabilities from risk management activities
  $ 167     $ 40     $ 84     $ 13     $ 30          
Other deferred credits and liabilities
    80       14       37       5       24          
 
Total derivatives designated as hedging instruments for regulatory purposes
  $ 247     $ 54     $ 121     $ 18     $ 54       N/A  
 
 
                                               
Derivatives designated as hedging instruments in cash flow and fair value hedges
                                               
Energy-related derivatives:
                                               
Liabilities from risk management activities
  $ 2     $     $     $     $     $ 2  
Other deferred credits and liabilities
    1                               1  
Interest rate derivatives:
                                               
Liabilities from risk management activities
    2                                
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges
  $ 5     $     $     $     $     $ 3  
 
 
                                               
Derivatives not designated as hedging instruments
                                               
Energy-related derivatives:
                                               
Liabilities from risk management activities
  $ 5     $     $     $     $     $ 5  
Other deferred credits and liabilities
    1                               1  
 
Total derivatives not designated as hedging instruments
  $ 6     $     $     $     $     $ 6  
 
 
                                               
Total liability derivatives
  $ 258     $ 54     $ 121     $ 18     $ 54     $ 9  
 
      All derivative instruments are measured at fair value. See Note (C) herein for additional information.
      At September 30, 2010, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet were as follows:
                                         
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet   Southern   Alabama   Georgia   Gulf   Mississippi
Location   Company   Power   Power   Power   Power
 
    (in millions)
Energy-related derivatives:
                                       
Other regulatory assets, current
  $ (167 )   $ (40 )   $ (84 )   $ (13 )   $ (30 )
Other regulatory assets, deferred
    (80 )     (14 )     (37 )     (5 )     (24 )
 
Total energy-related derivative gains (losses)
  $ (247 )   $ (54 )   $ (121 )   $ (18 )   $ (54 )
 
      For the three months and nine months ended September 30, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $9 million and $17 million, respectively. These amounts were offset with changes in the fair value of the hedged debt.
 
      For the three months and nine months ended September 30, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Mississippi Power’s statements of income were $5 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      For the three months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
                                     
    Gain (Loss)    
    Recognized in OCI   Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow   on Derivative   into Income (Effective Portion)
Hedging Relationships   (Effective Portion)   Statements of Income Location   Amount
    2010   2009       2010   2009
 
    (in millions)
      (in millions)
Southern Company
                                   
Energy-related derivatives
  $ 3     $ (1 )   Fuel   $     $  
Interest rate derivatives
    (1 )     (3 )   Interest expense     (7 )     (12 )
 
Total
  $ 2     $ (4 )       $ (7 )   $ (12 )
 
Alabama Power
                                   
Interest rate derivatives
  $     $ (1 )   Interest expense   $     $ (3 )
 
Georgia Power
                                   
Interest rate derivatives
  $     $ (1 )   Interest expense   $ (3 )   $ (6 )
 
Gulf Power
                                   
Interest rate derivatives
  $     $ (1 )   Interest expense   $     $  
 
Southern Power
                                   
Energy-related derivatives
  $ 3     $ (1 )   Fuel   $     $  
Interest rate derivatives
              Interest expense     (3 )     (2 )
 
Total
  $ 3     $ (1 )       $ (3 )   $ (2 )
 
      For the nine months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
                                     
    Gain (Loss)    
    Recognized in OCI   Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow   on Derivative   into Income (Effective Portion)
Hedging Relationships   (Effective Portion)   Statements of Income Location   Amount
    2010   2009       2010   2009
 
    (in millions)
      (in millions)
Southern Company
                                   
Energy-related derivatives
  $ 4     $     Fuel   $     $  
Interest rate derivatives
    (3 )     (6 )   Interest expense     (24 )     (34 )
 
Total
  $ 1     $ (6 )       $ (24 )   $ (34 )
 
Alabama Power
                                   
Interest rate derivatives
  $     $ (5 )   Interest expense   $ (1 )   $ (9 )
 
Georgia Power
                                   
Interest rate derivatives
  $     $     Interest expense   $ (13 )   $ (17 )
 
Gulf Power
                                   
Interest rate derivatives
  $ (1 )   $ (1 )   Interest expense   $ (1 )   $ (1 )
 
Southern Power
                                   
Energy-related derivatives
  $ 4     $     Fuel   $     $  
Interest rate derivatives
              Interest expense     (8 )     (7 )
 
Total
  $ 4     $         $ (8 )   $ (7 )
 
      There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      For the three months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:
                     
Derivatives not Designated   Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments   Statements of Income Location   Amount
        2010   2009
 
        (in millions)
Southern Company
                   
Energy-related derivatives
  Wholesale revenues   $ (1 )   $ 4  
 
  Fuel     (1 )     (1 )
 
  Purchased power     (1 )     (1 )
 
Total
      $ (3 )   $ 2  
 
Southern Power
                   
Energy-related derivatives
  Wholesale revenues   $ (1 )   $ 4  
 
  Fuel     (1 )     (1 )
 
  Purchased power     (1 )     (1 )
 
Total
      $ (3 )   $ 2  
 
      For the nine months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:
                     
Derivatives not Designated   Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments   Statements of Income Location   Amount
        2010   2009
 
        (in millions)
Southern Company
                   
Energy-related derivatives
  Wholesale revenues   $     $ 9  
 
  Fuel     (1 )     (4 )
 
  Purchased power     (1 )     (4 )
 
Total
      $ (2 )   $ 1  
 
Southern Power
                   
Energy-related derivatives
  Wholesale revenues   $     $ 9  
 
  Fuel     (1 )     (4 )
 
  Purchased power     (1 )     (4 )
 
Total
      $ (2 )   $ 1  
 
      Contingent Features
      The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2010, the fair value of derivative liabilities with contingent features, by registrant, was as follows:
                                                 
    Southern   Alabama   Georgia   Gulf   Mississippi   Southern
    Company   Power   Power   Power   Power   Power
 
    (in millions)                      
Derivative liabilities
  $ 51     $ 9     $ 33     $ 2     $ 6     $ 1  
      At September 30, 2010, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was $51 million for each registrant.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
      Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, 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.
  (I)   SEGMENT AND RELATED INFORMATION
      Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $93 million and $288 million for the three months and nine months ended September 30, 2010, respectively, and $148 million and $421 million for the three months and nine months ended September 30, 2009, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, renewable energy projects, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:
                                                           
    Electric Utilities            
    Traditional                                
    Operating   Southern                   All        
    Companies   Power   Eliminations   Total   Other   Eliminations   Consolidated
 
        (in millions)
Three Months Ended September 30, 2010:
                                                       
Operating revenues
  $ 5,066     $ 357     $ (124 )   $ 5,299     $ 40     $ (19 )   $ 5,320  
Segment net income (loss)*
    757       61             818       (1 )           817  
Nine Months Ended
September  30, 2010:
                                                       
Operating revenues
  $ 13,127     $ 862     $ (367 )   $ 13,622     $ 122     $ (59 )   $ 13,685  
Segment net income (loss)*
    1,713       106             1,819       4       (1 )     1,822  
Total assets at September 30, 2010
  $ 51,329     $ 3,223     $ (176 )   $ 54,376     $ 1,092     $ (573 )   $ 54,895  
 
 
                                                       
Three Months Ended September  30, 2009:
                                                       
Operating revenues
  $ 4,543     $ 283     $ (169 )   $ 4,657     $ 43     $ (18 )   $ 4,682  
Segment net income (loss)*
    726       67             793       (2 )     (1 )     790  
Nine Months Ended
September  30, 2009:
                                                       
Operating revenues
  $ 11,881     $ 745     $ (471 )   $ 12,155     $ 130     $ (52 )   $ 12,233  
Segment net income (loss)*
    1,449       126             1,575       (182 )     1       1,394  
Total assets at December 31, 2009
  $ 48,403     $ 3,043     $ (143 )   $ 51,303     $ 1,223     $ (480 )   $ 52,046  
 
*   After dividends on preferred and preference stock of subsidiaries
      Products and Services
                                 
    Electric Utilities’ Revenues
Period   Retail   Wholesale   Other   Total
 
    (in millions)
Three Months Ended September 30, 2010
  $ 4,573     $ 566     $ 160     $ 5,299  
Three Months Ended September 30, 2009
    3,997       519       141       4,657  
 
                               
Nine Months Ended September 30, 2010
  $ 11,603     $ 1,581     $ 438     $ 13,622  
Nine Months Ended September 30, 2009
    10,355       1,408       392       12,155  
 

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PART II — OTHER INFORMATION
Item 1.  Legal Proceedings.
      See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A.  Risk Factors.
      See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

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Item 6.   Exhibits.
         
(4) Instruments Describing Rights of Security Holders, Including Indentures
 
       
Southern Company
 
       
(a)1
  -   Sixth Supplemental Indenture to the Senior Note Indenture dated as of September 17, 2010, providing for the issuance of the Series 2010A 2.375% Senior Notes due September 15, 2015. (Designated in Form 8-K dated September 13, 2010, File No. 1-3526, as Exhibit 4.2.)
 
       
Alabama Power
 
       
(b)1
  -   Forty-Fourth Supplemental Indenture to Senior Note Indenture dated as of October 5, 2010, providing for the issuance of the Series 2010A 3.375% Senior Notes due October 1, 2020. (Designated in Form 8-K dated September 27, 2010, File No. 1-3164, as Exhibit 4.2.)
 
       
Georgia Power
 
       
(c)1
  -   Forty-Second Supplemental Indenture to Senior Note Indenture dated as of August 31, 2010, providing for the issuance of the Series 2010C 4.75% Senior Notes due September 1, 2040. (Designated in Form 8-K dated August 26, 2010, File No. 1-6468, as Exhibit 4.2.)
 
       
(c)2
  -   Forty-Third Supplemental Indenture to Senior Note Indenture dated as of September 23, 2010, providing for the issuance of the Series 2010D 1.30% Senior Notes due September 15, 2013. (Designated in Form 8-K dated September 20, 2010, File No. 1-6468, as Exhibit 4.2.)
 
       
Gulf Power
 
       
(d)1
  -   Seventeenth Supplemental Indenture to Senior Note Indenture dated as of September 17, 2010, providing for the issuance of the Series 2010B 5.10% Senior Notes due October 1, 2040. (Designated in Form 8-K dated September 9, 2010, File No. 001-31737, as Exhibit 4.2.)
 
       
(10) Material Contracts
 
       
Southern Company
 
       
(a)1
  -   Base Salaries of Named Executive Officers.
 
       
(a)2
  -   Restricted Stock Award Agreement between Southern Company and W. Paul Bowers dated July 27, 2010.
 
       
Alabama Power
 
       
(b)1
  -   Base Salaries of Named Executive Officers.
 
       
(b)2
  -   Deferred Compensation Agreement between Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and SCS and Philip C. Raymond dated September 15, 2010.
 
       
(b)3
  -   Consulting Agreement between Jerry L. Stewart and SCS dated October 11, 2010.

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Gulf Power
 
       
(d)1
  -   Base Salaries of Named Executive Officers.
 
       
(d)2
  -   Deferred Compensation Agreement between Southern Company, Georgia Power, Gulf Power, and Southern Nuclear and Bentina C. Terry dated August 1, 2010.
 
       
(d)3
  -   Deferred Compensation Agreement between Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and SCS and Philip C. Raymond dated September 15, 2010. See Exhibit 10(b)2 herein.
 
       
Mississippi Power
 
       
(e)1
  -   Base Salaries of Named Executive Officers.
 
       
(e)2
  -   Retention Agreement between Edward Day, VI and SCS dated January 22, 2008, Amendment to Retention Agreement dated December 12, 2008, and Amendment of Retention Agreement dated July 29, 2010.
 
       
(24) Power of Attorney and Resolutions
 
       
Southern Company
 
       
(a)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
 
       
(a)2
  -   Power of Attorney for Art P. Beattie.
 
       
Alabama Power
 
       
(b)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
 
       
(b)2
  -   Power of Attorney for Philip C. Raymond.
 
       
Georgia Power
 
       
(c)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
 
       
Gulf Power
 
       
(d)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.)
 
       
(d)2
  -   Power of Attorney for Richard S. Teel.
 
       
Mississippi Power
 
       
(e)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
 
       
(e)2
  -   Power of Attorney for Edward Day, VI.

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(e)3
  -   Power of Attorney for Moses H. Feagin.
 
       
Southern Power
 
       
(f)1
  -   Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
 
       
(f)2
  -   Power of Attorney for Oscar C. Harper.
 
       
(31) Section 302 Certifications
 
       
Southern Company
 
       
(a)1
  -   Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(a)2
  -   Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
Alabama Power
 
       
(b)1
  -   Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(b)2
  -   Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
Georgia Power
 
       
(c)1
  -   Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(c)2
  -   Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
Gulf Power
 
       
(d)1
  -   Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(d)2
  -   Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
Mississippi Power
 
       
(e)1
  -   Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(e)2
  -   Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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Southern Power
 
       
(f)1
  -   Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(f)2
  -   Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
       
(32) Section 906 Certifications
 
       
Southern Company
 
       
(a)
  -   Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
       
Alabama Power
 
       
(b)
  -   Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
       
Georgia Power
 
       
(c)
  -   Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
       
Gulf Power
 
       
(d)
  -   Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
       
Mississippi Power
 
       
(e)
  -   Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
 
       
Southern Power
 
       
(f)
  -   Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

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(101) XBRL – Related Documents
 
       
Southern Company
 
       
INS   XBRL Instance Document
SCH   XBRL Taxonomy Extension Schema Document
CAL   XBRL Taxonomy Calculation Linkbase Document
DEF   XBRL Definition Linkbase Document
LAB   XBRL Taxonomy Label Linkbase Document
PRE   XBRL Taxonomy Presentation Linkbase Document

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THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      THE SOUTHERN COMPANY    
 
           
 
  By   David M. Ratcliffe    
 
      Chairman and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Art P. Beattie    
 
      Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      ALABAMA POWER COMPANY    
 
           
 
  By   Charles D. McCrary    
 
      President and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Philip C. Raymond    
 
      Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      GEORGIA POWER COMPANY    
 
           
 
  By   Michael D. Garrett    
 
      President and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Ronnie R. Labrato    
 
      Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      GULF POWER COMPANY    
 
           
 
  By   Susan N. Story    
 
      President and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Richard S. Teel    
 
      Vice President and Chief Financial Officer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      MISSISSIPPI POWER COMPANY    
 
           
 
  By   Edward Day, VI    
 
      President and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Moses H. Feagin    
 
      Vice President, Treasurer, and Chief Financial Officer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
             
 
      SOUTHERN POWER COMPANY    
 
           
 
  By   Oscar C. Harper    
 
      President and Chief Executive Officer
(Principal Executive Officer)
   
 
           
 
  By   Michael W. Southern    
 
      Senior Vice President, Treasurer, and Chief Financial Officer
(Principal Financial Officer)
   
 
           
 
  By   /s/ Melissa K. Caen    
 
     
 
(Melissa K. Caen, Attorney-in-fact)
   
Date: November 5, 2010

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