e10vq
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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 June 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
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
  58-0690070 
 
       
1-3164
  Alabama Power Company
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35291
(205) 257-1000
  63-0004250 
 
       
1-6468
  Georgia Power Company
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
  58-0257110 
 
       
0-2429
  Gulf Power Company
(A Florida Corporation)
One Energy Place
Pensacola, Florida 32520
(850) 444-6111
  59-0276810 
 
       
001-11229
  Mississippi Power Company
(A Mississippi Corporation)
2992 West Beach
Gulfport, Mississippi 39501
(228) 864-1211
  64-0205820 
 
       
333-98553
  Southern Power Company
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
  58-2598670 

 


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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 June 30, 2010  
The Southern Company
  Par Value $5 Per Share     830,705,693  
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
June 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  
           
        36  
        36  
        37  
        38  
        40  
           
        55  
        55  
        56  
        57  
        59  
           
        77  
        77  
        78  
        79  
        81  
           
        97  
        97  
        98  
        99  
        101  
           
        120  
        120  
        121  
        122  
        124  
        135  
Item 3.       33  
Item 4.       33  
Item 4T.       33  

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2010
             
        Page
        Number
PART II – OTHER INFORMATION
       
   
 
       
Item 1.         162
Item 1A.         162
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.         163
          166

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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
Gulf Power
  Gulf Power Company
IGCC
  Integrated coal gasification combined cycle
IIC
  Intercompany Interchange Contract
Internal Revenue Code
  Internal Revenue Code of 1986, as amended
IRS
  Internal Revenue Service
KWH
  Kilowatt-hour
LIBOR
  London Interbank Offered Rate
Mirant
  Mirant Corporation
Mississippi Power
  Mississippi Power Company
mmBtu
  Million British thermal unit
Moody’s
  Moody’s Investors Service
MW
  Megawatt
MWH
  Megawatt-hour
NRC
  Nuclear Regulatory Commission
NSR
  New Source Review
OCI
  Other Comprehensive Income
PEP
  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 ECR
  Alabama Power’s energy cost recovery rate mechanism
registrants
  Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS
  Southern Company Services, Inc.
SEC
  Securities and Exchange Commission
Southern Company
  The Southern Company
Southern Company system
  Southern Company, the traditional operating companies, Southern Power, and other subsidiaries

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DEFINITIONS
(continued)
     
Term   Meaning
SouthernLINC Wireless
  Southern Communications Services, Inc.
Southern Nuclear
  Southern Nuclear Operating Company, Inc.
Southern Power
  Southern Power Company
S&P
  Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies
  Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse
  Westinghouse Electric Company LLC
wholesale revenues
  revenues generated from sales for resale

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, 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, 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, IRS audits, and Mirant matters;
 
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
  variations in demand for electricity, including those relating to weather, the general economy 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;
 
  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 Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 3,571,480     $ 3,293,012     $ 7,030,400     $ 6,357,671  
Wholesale revenues
    473,229       437,750       1,014,816       889,164  
Other electric revenues
    142,152       128,403       277,587       251,201  
Other revenues
    20,558       25,999       41,933       53,435  
 
                       
Total operating revenues
    4,207,419       3,885,164       8,364,736       7,551,471  
 
                       
Operating Expenses:
                               
Fuel
    1,628,985       1,449,138       3,274,143       2,855,405  
Purchased power
    128,373       133,188       254,939       240,832  
Other operations and maintenance
    918,391       831,214       1,826,415       1,702,295  
MC Asset Recovery litigation settlement
                      202,000  
Depreciation and amortization
    366,553       377,341       709,933       767,099  
Taxes other than income taxes
    214,066       208,089       426,261       407,969  
 
                       
Total operating expenses
    3,256,368       2,998,970       6,491,691       6,175,600  
 
                       
Operating Income
    951,051       886,194       1,873,045       1,375,871  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    45,300       47,500       94,691       90,112  
Interest income
    4,807       4,870       9,594       11,778  
Leveraged lease income (losses)
    669       8,676       6,800       18,117  
Gain on disposition of lease termination
          26,300             26,300  
Loss on extinguishment of debt
          (17,184 )           (17,184 )
Interest expense, net of amounts capitalized
    (218,669 )     (232,830 )     (441,151 )     (458,557 )
Other income (expense), net
    (9,267 )     (3,001 )     (22,704 )     (16,827 )
 
                       
Total other income and (expense)
    (177,160 )     (165,669 )     (352,770 )     (346,261 )
 
                       
Earnings Before Income Taxes
    773,891       720,525       1,520,275       1,029,610  
Income taxes
    247,502       225,717       483,183       392,886  
 
                       
Consolidated Net Income
    526,389       494,808       1,037,092       636,724  
Dividends on Preferred and Preference Stock of Subsidiaries
    16,195       16,195       32,390       32,390  
 
                       
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
  $ 510,194     $ 478,613     $ 1,004,702     $ 604,334  
 
                       
Common Stock Data:
                               
Earnings per share (EPS) -
                               
Basic EPS
  $ 0.62     $ 0.61     $ 1.22     $ 0.77  
Diluted EPS
  $ 0.61     $ 0.60     $ 1.21     $ 0.77  
Average number of shares of common stock outstanding (in thousands)
                               
Basic
    828,363       790,748       825,444       785,303  
Diluted
    832,622       792,068       828,752       786,865  
Cash dividends paid per share of common stock
  $ 0.4550     $ 0.4375     $ 0.8925     $ 0.8575  
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 Six Months  
    Ended June 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Consolidated net income
  $ 1,037,092     $ 636,724  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    867,583       895,354  
Deferred income taxes
    215,318       (13,807 )
Deferred revenues
    (47,361 )     (26,295 )
Allowance for equity funds used during construction
    (94,691 )     (90,112 )
Leveraged lease income (losses)
    (6,800 )     (18,117 )
Gain on disposition of lease termination
          (26,300 )
Loss on extinguishment of debt
          17,184  
Pension, postretirement, and other employee benefits
    (1,252 )     (10,939 )
Stock based compensation expense
    23,809       18,956  
Hedge settlements
    1,530       (16,167 )
Generation construction screening costs
    (50,554 )     (14,049 )
Other, net
    (57,830 )     42,293  
Changes in certain current assets and liabilities —
               
-Receivables
    (255,399 )     74,770  
-Fossil fuel stock
    72,216       (375,888 )
-Materials and supplies
    (6,806 )     (20,079 )
-Other current assets
    (88,138 )     (96,394 )
-Accounts payable
    (52,091 )     14,711  
-Accrued taxes
    (79,767 )     (140,308 )
-Accrued compensation
    (33,932 )     (298,670 )
-Other current liabilities
    (27,965 )     66,748  
 
           
Net cash provided from operating activities
    1,414,962       619,615  
 
           
Investing Activities:
               
Property additions
    (1,935,716 )     (2,192,959 )
Investment in restricted cash from pollution control revenue bonds
    (11 )     (49,478 )
Distribution of restricted cash from pollution control revenue bonds
    11,403       59,741  
Nuclear decommissioning trust fund purchases
    (515,901 )     (823,416 )
Nuclear decommissioning trust fund sales
    488,561       788,690  
Proceeds from property sales
    216       339,903  
Cost of removal, net of salvage
    (59,989 )     (63,705 )
Change in construction payables
    12,934       128,101  
Other investing activities
    (37,037 )     8,063  
 
           
Net cash used for investing activities
    (2,035,540 )     (1,805,060 )
 
           
Financing Activities:
               
Increase in notes payable, net
    244,037       148,090  
Proceeds —
               
Long-term debt issuances
    1,146,000       1,785,474  
Common stock issuances
    341,447       539,088  
Redemptions —
               
Long-term debt
    (754,304 )     (199,929 )
Payment of common stock dividends
    (735,009 )     (670,226 )
Payment of dividends on preferred and preference stock of subsidiaries
    (32,394 )     (32,465 )
Other financing activities
    (12,643 )     (19,327 )
 
           
Net cash provided from financing activities
    197,134       1,550,705  
 
           
Net Change in Cash and Cash Equivalents
    (423,444 )     365,260  
Cash and Cash Equivalents at Beginning of Period
    689,722       416,581  
 
           
Cash and Cash Equivalents at End of Period
  $ 266,278     $ 781,841  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $40,130 and $38,594 capitalized for 2010 and 2009, respectively)
  $ 387,451     $ 386,729  
Income taxes (net of refunds)
  $ 285,247     $ 468,278  
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 June 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 266,278     $ 689,722  
Restricted cash and cash equivalents
    31,743       43,135  
Receivables —
               
Customer accounts receivable
    1,180,856       953,222  
Unbilled revenues
    496,265       394,492  
Under recovered regulatory clause revenues
    193,998       333,459  
Other accounts and notes receivable
    352,798       374,670  
Accumulated provision for uncollectible accounts
    (27,152 )     (24,568 )
Fossil fuel stock, at average cost
    1,383,220       1,446,984  
Materials and supplies, at average cost
    805,205       793,847  
Vacation pay
    145,422       145,049  
Prepaid expenses
    479,878       508,338  
Other regulatory assets, current
    175,237       166,549  
Other current assets
    40,514       48,558  
 
           
Total current assets
    5,524,262       5,873,457  
 
           
Property, Plant, and Equipment:
               
In service
    55,698,851       53,587,853  
Less accumulated depreciation
    19,647,708       19,121,271  
 
           
Plant in service, net of depreciation
    36,051,143       34,466,582  
Nuclear fuel, at amortized cost
    677,178       593,119  
Construction work in progress
    3,902,173       4,170,596  
 
           
Total property, plant, and equipment
    40,630,494       39,230,297  
 
           
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,055,036       1,070,117  
Leveraged leases
    614,830       610,252  
Miscellaneous property and investments
    286,142       282,974  
 
           
Total other property and investments
    1,956,008       1,963,343  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,167,278       1,047,452  
Unamortized debt issuance expense
    199,558       208,346  
Unamortized loss on reacquired debt
    255,180       254,936  
Deferred under recovered regulatory clause revenues
    479,896       373,245  
Other regulatory assets, deferred
    2,724,931       2,701,910  
Other deferred charges and assets
    436,883       392,880  
 
           
Total deferred charges and other assets
    5,263,726       4,978,769  
 
           
Total Assets
  $ 53,374,490     $ 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 June 30,     At December 31,  
Liabilities and Stockholders’ Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 1,514,465     $ 1,112,705  
Notes payable
    881,638       639,199  
Accounts payable
    1,282,523       1,329,448  
Customer deposits
    335,625       330,582  
Accrued taxes —
               
Accrued income taxes
    25,664       13,005  
Unrecognized tax benefits
    168,400       165,645  
Other accrued taxes
    319,321       398,384  
Accrued interest
    220,153       218,188  
Accrued vacation pay
    181,150       183,911  
Accrued compensation
    222,301       247,950  
Liabilities from risk management activities
    124,154       124,648  
Other regulatory liabilities, current
    297,328       528,147  
Other current liabilities
    362,728       292,016  
 
           
Total current liabilities
    5,935,450       5,583,828  
 
           
Long-term Debt
    18,134,554       18,131,244  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    6,725,211       6,454,822  
Deferred credits related to income taxes
    241,669       248,232  
Accumulated deferred investment tax credits
    457,809       447,650  
Employee benefit obligations
    2,287,633       2,304,344  
Asset retirement obligations
    1,233,019       1,201,343  
Other cost of removal obligations
    1,119,382       1,091,425  
Other regulatory liabilities, deferred
    233,355       277,932  
Other deferred credits and liabilities
    391,623       345,888  
 
           
Total deferred credits and other liabilities
    12,689,701       12,371,636  
 
           
Total Liabilities
    36,759,705       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 — 1 billion shares
               
Issued — June 30, 2010: 831,147,821 Shares
               
— December 31, 2009: 820,151,801 Shares
               
Treasury — June 30, 2010: 442,128 Shares
               
— December 31, 2009: 505,116 Shares
               
Par value
    4,155,676       4,100,742  
Paid-in capital
    3,310,322       2,994,245  
Treasury, at cost
    (14,923 )     (14,797 )
Retained earnings
    8,156,346       7,884,922  
Accumulated other comprehensive loss
    (74,460 )     (87,778 )
 
           
Total Common Stockholders’ Equity
    15,532,961       14,877,334  
Preferred and Preference Stock of Subsidiaries
    707,328       707,328  
 
           
Total Stockholders’ Equity
    16,240,289       15,584,662  
 
           
Total Liabilities and Stockholders’ Equity
  $ 53,374,490     $ 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 STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Consolidated Net Income
  $ 526,389     $ 494,808     $ 1,037,092     $ 636,724  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(1,267), $(1,744), $(481), and $(982), respectively
    (1,982 )     (2,811 )     (781 )     (1,664 )
Reclassification adjustment for amounts included in net income, net of tax of $3,124, $4,630, $6,676, and $8,463, respectively
    4,928       7,370       10,574       13,468  
Marketable securities:
                               
Change in fair value, net of tax of $472, $1,204, $1,616, and $1,295, respectively
    770       2,935       2,796       3,669  
Pension and other post retirement benefit plans:
                               
Reclassification adjustment for amounts included in net income, net of tax of $230, $221, $460, and $443, respectively
    364       349       729       699  
 
                       
Total other comprehensive income (loss)
    4,080       7,843       13,318       16,172  
 
                       
Dividends on preferred and preference stock of subsidiaries
    (16,195 )     (16,195 )     (32,390 )     (32,390 )
 
                       
Comprehensive Income
  $ 514,274     $ 486,456     $ 1,018,020     $ 620,506  
 
                       
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
SECOND QUARTER 2010 vs. SECOND 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$31.6   6.6   $400.4   66.2
 
Southern Company’s second quarter 2010 net income after dividends on preferred and preference stock of subsidiaries was $510.2 million ($0.62 per share) compared to $478.6 million ($0.61 per share) for second quarter 2009. The increase for the second quarter 2010 when compared to the corresponding period in 2009 was primarily the result of increases in revenues as a result of warmer weather, 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 Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant for environmental costs (Rate CNP Environmental) that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for the second quarter 2010 was partially offset by increases in operations and maintenance expense, a gain in the second quarter 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.
Southern Company’s year-to-date 2010 net income after dividends on preferred and preference stock of subsidiaries was $1.00 billion ($1.22 per share) compared to $604.3 million ($0.77 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 as a result of warmer weather in the second quarter 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 expense, 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$278.5   8.5   $672.7   10.6
 
In the second quarter 2010, retail revenues were $3.57 billion compared to $3.29 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $7.03 billion compared to $6.36 billion for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Second Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions) (% change)
Retail – prior year
  $ 3,293.0             $ 6,357.7          
Estimated change in —
                               
Rates and pricing
    57.9       1.8       134.6       2.1  
Sales growth (decline)
    30.9       0.9       42.4       0.7  
Weather
    54.0       1.6       179.8       2.8  
Fuel and other cost recovery
    135.7       4.1       315.9       5.0  
 
Retail – current year
  $ 3,571.5       8.4 %   $ 7,030.4       10.6 %
 
Revenues associated with changes in rates and pricing increased in the second 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, 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. These increases were partially offset by lower contributions from market-driven rates for sales to industrial customers at Georgia Power.
Revenues attributable to changes in sales increased in the second quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 due to increases in weather-adjusted retail KWH sales of 3.8% and 3.2%, respectively. For the second quarter 2010, weather-adjusted residential KWH sales increased 1.4%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales increased 12.3%. For year-to-date 2010, weather-adjusted residential KWH sales increased 1.5%, weather-adjusted commercial KWH sales decreased 0.7%, and weather-adjusted industrial KWH sales increased 9.7%. Increased demand in the primary metals, chemicals, paper, and transportation sectors were the main contributors to the increases in weather-adjusted industrial KWH sales for the second quarter and year-to-date 2010.
Revenues resulting from changes in weather increased in the second quarter and for year-to-date 2010 as a result of warmer weather in the second 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 $135.7 million in the second quarter 2010 and $315.9 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$35.4   8.1   $125.7   14.1
 
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 second quarter 2010, wholesale revenues were $473.2 million compared to $437.8 million for the corresponding period in 2009. The increase was primarily due to energy and capacity revenues under new PPAs that began in January and June 2010 at Southern Power, as well as energy sales not covered by PPAs at Southern Power as a result of more favorable weather in the second quarter 2010 when 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.
For year-to-date 2010, wholesale revenues were $1.01 billion compared to $889.2 million for the corresponding period in 2009. This increase was primarily due to energy and capacity revenues under new PPAs that began in January and June 2010 at Southern Power, as well as energy sales not covered by PPAs at Southern Power due to more favorable weather year-to-date 2010 when compared to the corresponding period in 2009.
Other Electric Revenues
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$13.8   10.7   $26.4   10.5
 
In the second quarter 2010, other electric revenues were $142.2 million compared to $128.4 million for the corresponding period in 2009. This increase was primarily the result of a $4.6 million increase in transmission revenues, a $4.8 million increase in co-generation revenues due to increased sales volume, a $1.2 million increase in rents from electric property, and a $1.3 million increase in outdoor lighting revenues.
For year-to-date 2010, other electric revenues were $277.6 million compared to $251.2 million for the corresponding period in 2009. This increase was primarily the result of a $10.4 million increase in transmission revenues, a $7.6 million increase in co-generation revenues due to increased sales volume, a $3.6 million increase in rents from electric property, and a $1.4 million increase in outdoor lighting revenues.
Revenues from co-generation and other energy services are generally offset by related expenses and do not affect net income.
Other Revenues
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(5.4)   (20.9)   $(11.5)   (21.5)
 
In the second quarter 2010, other revenues were $20.6 million compared to $26.0 million for the corresponding period in 2009. The decrease was primarily the result of a $5.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

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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 $41.9 million compared to $53.4 million for the corresponding period in 2009. The decrease was primarily the result of a $10.7 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
                                 
    Second Quarter 2010     Year-to-Date 2010  
    vs.     vs.  
    Second Quarter 2009     Year-to-Date 2009  
    (change in millions)   (% change)     (change in millions)   (% change)  
Fuel*
  $ 179.8     12.4     $ 418.7     14.7  
Purchased power
    (4.8 )      (3.6)         14.1       5.9  
                     
Total fuel and purchased power expenses
  $ 175.0             $ 432.8          
                     
*   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 second quarter 2010 were $1.76 billion compared to $1.58 billion for the corresponding period in 2009. The increase was primarily the result of a $92.6 million increase related to total KWHs generated and purchased and an $82.4 million increase in the average cost of fuel and purchased power. The increase in total KWHs generated and purchased 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 $3.53 billion compared to $3.10 billion for the corresponding period in 2009. The increase was primarily the result of a $214.0 million increase related to total KWHs generated and purchased and a $218.8 million increase in the average cost of fuel and purchased power. The increase in total KWHs generated and purchased 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 affect 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:
                                                 
    Second Quarter   Second 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
    3.50       3.34       4.8       3.55       3.37       5.3  
Purchased power
    5.91       5.59       5.7       6.50       5.36       21.3  
 
Energy purchases will vary depending on demand for energy within the Southern Company service area, the market cost of available energy as compared to the cost of Southern Company system-generated energy, and the availability of Southern Company system generation.

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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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$87.2   10.5   $124.1   7.3
 
In the second quarter 2010, other operations and maintenance expenses were $918.4 million compared to $831.2 million for the corresponding period in 2009. The increase was primarily the result of a $37.7 million increase in fossil, hydro, and nuclear expenses, a $22.0 million increase in commodity and labor costs, a $20.9 million increase in transmission and distribution expenses, a $3.6 million increase in administrative and general expenses, and a $3.0 million increase in customer service and sales expenses.
For year-to-date 2010, other operations and maintenance expenses were $1.83 billion compared to $1.70 billion for the corresponding period in 2009. The increase was primarily the result of a $70.0 million increase in fossil, hydro, and nuclear expenses, a $40.1 million increase in commodity and labor costs, a $28.7 million increase in transmission and distribution expenses, and a $19.1 million increase in affiliated service companies’ expenses. The increase was partially offset by a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan at Georgia Power.
MC Asset Recovery Litigation Settlement
             
Second Quarter 2010 vs. Second 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(10.8)   (2.9)   $(57.2)   (7.5)
 
In the second quarter 2010, depreciation and amortization was $366.5 million compared to $377.3 million for the corresponding period in 2009. The decrease was primarily the result of amortization of $54.0 million of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. The decrease was partially offset by depreciation on additional plant in service related to environmental, transmission, and distribution projects.
For year-to-date 2010, depreciation and amortization was $709.9 million compared to $767.1 million for the corresponding period in 2009. The decrease was primarily the result of amortization of $114.3 million of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. The decrease was partially offset by depreciation on additional plant in service related to environmental, transmission, and distribution projects.
See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters – Georgia Power – Cost of Removal” for additional information on the amortization of the other cost of removal regulatory liability.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$6.0   2.9   $18.3   4.5
 
In the second quarter 2010, taxes other than income taxes were $214.1 million compared to $208.1 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $426.3 million compared to $408.0 million for the corresponding period in 2009. The second quarter and year-to-date 2010 increases were primarily the result of higher municipal franchise fees resulting from increased retail revenues at Georgia Power and increases in ad valorem taxes at Mississippi Power.
Allowance for Funds Used During Construction
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.2)   (4.6)   $4.6   5.1
 
In the second quarter 2010, AFUDC equity was $45.3 million compared to $47.5 million for the corresponding period in 2009. The decrease was primarily due to the completion of environmental projects at Alabama Power and Gulf Power, partially offset by increases in construction work in progress balances related to three new combined cycle units and two new nuclear generating units at Georgia Power.
For year-to-date 2010, AFUDC equity was $94.7 million compared to $90.1 million for the corresponding period in 2009. The increase was primarily due to the increase in construction work in progress balances related to three new combined cycle units and two new nuclear generating units at Georgia Power, partially offset by the completion of environmental projects at Alabama Power and Gulf Power.
Leveraged Lease Income
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(8.0)   (92.3)   $(11.3)   (62.5)
 
In the second quarter 2010, leveraged lease income was $0.7 million compared to $8.7 million for the corresponding period in 2009. For year-to-date 2010, leveraged lease income was $6.8 million compared to $18.1 million for the corresponding period in 2009. The second quarter and year-to-date 2010 decreases were primarily related to the early termination of two leveraged lease investments in the second quarter of 2009.
Gain on Disposition of Lease Termination
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(26.3)   N/M   $(26.3)   N/M
 
N/M – Not Meaningful
In the second quarter 2009, Southern Company terminated two international leveraged lease investments early which resulted in a gain of $26.3 million.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Loss on Extinguishment of Debt
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(17.2)   N/M   $(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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(14.1)   (6.1)   $(17.4)   (3.8)
 
In the second quarter 2010, interest expense, net of amounts capitalized was $218.7 million compared to $232.8 million for the corresponding period in 2009. The decrease was primarily due to an $8.9 million decrease related to lower average interest rates on variable rate debt and a $10.2 million decrease in other interest charges. Partially offsetting this decrease was a $3.9 million increase associated with $420.4 million in additional debt outstanding at June 30, 2010 when compared to June 30, 2009.
For year-to-date 2010, interest expense, net of amounts capitalized was $441.2 million compared to $458.6 million for the corresponding period in 2009. The decrease was primarily related to a $19.2 million decrease related to lower average interest rates on variable rate debt and a $13.8 million decrease in other interest charges. Partially offsetting this decrease was a $17.2 million increase associated with $420.4 million in additional debt outstanding at June 30, 2010 when compared to June 30, 2009.
Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$21.8   9.7   $90.3   23.0
 
In the second quarter 2010, income taxes were $247.5 million compared to $225.7 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in the second 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 $483.2 million compared to $392.9 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.
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 under “Effective Tax Rate” and “Unrecognized Tax Benefits” herein for additional information.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Recessionary conditions have impacted sales for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. 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.
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 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 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. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

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Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of 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 December 16, 2010. 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 June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new short-term standard. 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 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.

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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 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, the final regulation could significantly alter the options available for beneficial reuse. 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.
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 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 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 $669 million at June 30, 2010. Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of June 30, 2010, had a total over recovered fuel balance of approximately $133 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Public Interest Advocacy 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.
Retail Rate Matters
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. Through June 30, 2010, Georgia Power had amortized $155.3 million of the regulatory liability and currently expects to amortize the remaining allowed $108 million by December 31, 2010.
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.

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      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.
Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2010. The final outcome of this matter cannot now be determined.
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

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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.
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.
Income Tax Matters
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2008 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. On April 30, 2010, the Georgia Department of Revenue filed its notice of appeal with 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 Georgia Power’s 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.
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 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 “Retail Regulatory Matters – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” herein for additional information.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern 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

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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 extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Southern Company’s service territory. The ultimate impact of this matter cannot be determined at this time.
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.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at June 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 $1.4 billion for the first six months of 2010, an increase of $795.3 million from the corresponding period in 2009. Significant changes in operating cash flow for the first six months of 2010 compared to the corresponding period in 2009 include an increase in net income as previously discussed and a reduction in fossil fuel stock. Net cash used for investing activities totaled $2.0 billion for the first six months of 2010, an increase of $230.5 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 $197.1 million for the first six months of 2010, a decrease of $1.4 billion from the corresponding period in 2009, primarily due to fewer issuances of securities in the first six months of 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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Significant balance sheet changes for the first six months of 2010 include a decrease in cash and cash equivalents of $423.4 million and an increase of $1.4 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include an increase in equity of $655.6 million.
The market price of Southern Company’s common stock at June 30, 2010 was $33.28 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $18.70 per share, representing a market-to-book ratio of 178%, compared to $33.32, $18.15, and 184%, respectively, at the end of 2009. The dividend for the second quarter 2010 was $0.455 per share compared to $0.4375 per share in the second 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 $1.51 billion will be required through June 30, 2011 to fund maturities of long-term debt. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in 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.
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. 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 two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4). Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. 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.

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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 June 30, 2010, Southern Company and its subsidiaries had approximately $266 million of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks. Of the unused credit arrangements, $519 million expire in 2010, $1.0 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 $907 million contain provisions allowing one-year term loans executable at expiration. At June 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 June 30, 2010, Alabama Power renewed a $200 million credit agreement which contains a provision allowing a one-year term loan executable at expiration and extended the expiration date to 2011. In addition, subsequent to June 30, 2010, Georgia Power renewed a $40 million credit agreement which contains a provision allowing a two-year term loan executable at expiration and extended the expiration date to 2011. In addition, subsequent to June 30, 2010, Gulf Power increased it existing lines of credit by $15 million with an expiration of 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 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 June 30, 2010, the Southern Company system had approximately $879 million of commercial paper borrowings outstanding. 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 June 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 $469 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.6 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On 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 June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Southern Company (A3 senior unsecured), Georgia Power (A2 senior unsecured), Gulf Power (A2 senior unsecured), and Mississippi Power (A1 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of Southern Company and a financing subsidiary that issues commercial paper for the benefit of Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation ratings of Georgia Power (Baa1 and VMIG1), Gulf Power (Baa1 and VMIG1), and Mississippi Power (A3 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.
Market Price Risk
Southern Company’s market risk exposure relative to interest rate changes for the second 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 second 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 six months ended June 30, 2010 were as follows:
                 
    Second Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (272 )   $ (178 )
Contracts realized or settled
    67       111  
Current period changes(a)
    3       (135 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (202 )   $ (202 )
 
(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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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 was an increase of $70 million and a decrease of $24 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 June 30, 2010, Southern Company had a net hedge volume of 134 million mmBtu with a weighted average contract cost of approximately $1.56 per mmBtu above market prices, compared to 141 million mmBtu (includes location basis of 2 million mmBtu) at March 31, 2010 with a weighted average contract cost of approximately $2.05 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.
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   June 30, 2010   December 31, 2009
    (in millions)
Regulatory hedges
  $ (201 )   $ (175 )
Cash flow hedges
    (1 )     (2 )
Not designated
          (1 )
 
Total fair value
  $ (202 )   $ (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 six months ended June 30, 2010 were $2 million and $1 million, respectively. For the three months ended June 30, 2009, the total net unrealized gains (losses) recognized in income were immaterial. For the six months ended June 30, 2009, the total net unrealized gains (losses) recognized in income were $(1) million.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:
                                 
    June 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
            (in millions)        
Level 1
  $     $     $     $  
Level 2
    (202 )     (116 )     (85 )     (1 )
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (202 )   $ (116 )   $ (85 )   $ (1 )
 
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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 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
In the first six months of 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The 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. Georgia Power also 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. Southern Company issued approximately $277 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, during the three months ended June 30, 2010, Southern Company issued 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 $69 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.
In the first six months of 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 5, 2020. The 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, 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.
See Southern Company’s Condensed Consolidated Statements of Cash Flows herein for further details regarding financing activities during the first six 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 second 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.
A new wholesale contract billing system was implemented in the second quarter 2010 for Georgia Power, Gulf Power, and Southern Power for specific wholesale contracts. This system replaces individual billing applications that were used to bill wholesale contracts. A new fuel procurement system was implemented in May 2010 for Alabama Power, Georgia Power, Gulf Power, and Mississippi Power.
The implementation of these systems provides 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 Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the second quarter 2010 that have materially affected or are reasonably likely to materially affect Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting, other than as described in the next paragraph.

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In May 2010, Gulf Power implemented new general ledger, supply chain, and work management systems. A new wholesale contract billing system was implemented in the second quarter 2010 for Georgia Power, Gulf Power, and Southern Power for specific wholesale contracts. This system replaces individual billing applications that were used to bill wholesale contracts. A new fuel procurement system was implemented in May 2010 for Alabama Power, Georgia Power, Gulf Power, and Mississippi Power.
The implementation of these systems provides 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 Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 1,221,865     $ 1,119,606     $ 2,397,874     $ 2,177,743  
Wholesale revenues, non-affiliates
    137,517       153,912       309,341       312,607  
Wholesale revenues, affiliates
    52,322       52,493       150,656       136,845  
Other revenues
    50,543       40,505       99,521       79,087  
 
                       
Total operating revenues
    1,462,247       1,366,516       2,957,392       2,706,282  
 
                       
Operating Expenses:
                               
Fuel
    466,033       447,486       955,076       930,719  
Purchased power, non-affiliates
    12,718       26,123       30,601       41,667  
Purchased power, affiliates
    52,049       56,570       103,692       98,130  
Other operations and maintenance
    308,825       278,298       619,598       555,157  
Depreciation and amortization
    152,294       126,487       297,577       269,903  
Taxes other than income taxes
    81,458       82,039       163,331       162,320  
 
                       
Total operating expenses
    1,073,377       1,017,003       2,169,875       2,057,896  
 
                       
Operating Income
    388,870       349,513       787,517       648,386  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    7,136       19,153       20,374       35,878  
Interest income
    3,976       4,148       8,014       8,270  
Interest expense, net of amounts capitalized
    (76,132 )     (76,768 )     (150,694 )     (148,975 )
Other income (expense), net
    (5,189 )     (4,491 )     (11,690 )     (10,863 )
 
                       
Total other income and (expense)
    (70,209 )     (57,958 )     (133,996 )     (115,690 )
 
                       
Earnings Before Income Taxes
    318,661       291,555       653,521       532,696  
Income taxes
    118,884       105,357       241,130       190,366  
 
                       
Net Income
    199,777       186,198       412,391       342,330  
Dividends on Preferred and Preference Stock
    9,866       9,866       19,732       19,732  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 189,911     $ 176,332     $ 392,659     $ 322,598  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 189,911     $ 176,332     $ 392,659     $ 322,598  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(39), $(700), $(10), and $(1,586), respectively
    (63 )     (1,152 )     (17 )     (2,609 )
Reclassification adjustment for amounts included in net income, net of tax of $(67), $1,178, $543, and $2,239, respectively
    (111 )     1,938       892       3,683  
 
                       
Total other comprehensive income (loss)
    (174 )     786       875       1,074  
 
                       
Comprehensive Income
  $ 189,737     $ 177,118     $ 393,534     $ 323,672  
 
                       
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 Six Months  
    Ended June 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 412,391     $ 342,330  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    342,542       311,868  
Deferred income taxes
    123,648       5,182  
Allowance for equity funds used during construction
    (20,374 )     (35,878 )
Pension, postretirement, and other employee benefits
    (16,596 )     (16,568 )
Stock based compensation expense
    3,614       3,168  
Other, net
    (26,671 )     680  
Changes in certain current assets and liabilities —
               
-Receivables
    (48,514 )     206,523  
-Fossil fuel stock
    15,211       (59,418 )
-Materials and supplies
    (7,805 )     (9,094 )
-Other current assets
    (48,541 )     (62,618 )
-Accounts payable
    (88,154 )     (133,138 )
-Accrued taxes
    (44,836 )     25,199  
-Accrued compensation
    (21,023 )     (56,429 )
-Other current liabilities
    (77,168 )     18,302  
 
           
Net cash provided from operating activities
    497,724       540,109  
 
           
Investing Activities:
               
Property additions
    (483,493 )     (641,598 )
Distribution of restricted cash from pollution control revenue bonds
    5,241       32,758  
Nuclear decommissioning trust fund purchases
    (84,057 )     (124,057 )
Nuclear decommissioning trust fund sales
    84,057       124,057  
Cost of removal, net of salvage
    (15,708 )     (13,004 )
Change in construction payables
    (27,552 )     17,575  
Other investing activities
    (25,020 )     (19,448 )
 
           
Net cash used for investing activities
    (546,532 )     (623,717 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    59,997       (24,995 )
Proceeds —
               
Capital contributions from parent company
    10,821       11,510  
Pollution control revenue bonds
          53,000  
Senior notes issuances
          500,000  
Payment of preferred and preference stock dividends
    (19,727 )     (19,740 )
Payment of common stock dividends
    (271,350 )     (261,400 )
Other financing activities
    1,028       (6,033 )
 
           
Net cash provided from (used for) financing activities
    (219,231 )     252,342  
 
           
Net Change in Cash and Cash Equivalents
    (268,039 )     168,734  
Cash and Cash Equivalents at Beginning of Period
    368,016       28,181  
 
           
Cash and Cash Equivalents at End of Period
  $ 99,977     $ 196,915  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $7,941 and $15,005 capitalized for 2010 and 2009, respectively)
  $ 125,212     $ 122,624  
Income taxes (net of refunds)
  $ 204,060     $ 203,248  
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 June 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 99,977     $ 368,016  
Restricted cash and cash equivalents
    31,471       36,711  
Receivables —
               
Customer accounts receivable
    366,455       322,292  
Unbilled revenues
    166,593       134,875  
Under recovered regulatory clause revenues
    3,773       37,338  
Other accounts and notes receivable
    37,068       33,522  
Affiliated companies
    65,042       61,508  
Accumulated provision for uncollectible accounts
    (12,121 )     (9,551 )
Fossil fuel stock, at average cost
    387,625       394,511  
Materials and supplies, at average cost
    333,856       326,074  
Vacation pay
    54,255       53,607  
Prepaid expenses
    188,453       111,320  
Other regulatory assets, current
    31,971       34,347  
Other current assets
    6,076       6,203  
 
           
Total current assets
    1,760,494       1,910,773  
 
           
Property, Plant, and Equipment:
               
In service
    19,668,405       18,574,229  
Less accumulated provision for depreciation
    6,752,418       6,558,864  
 
           
Plant in service, net of depreciation
    12,915,987       12,015,365  
Nuclear fuel, at amortized cost
    303,851       253,308  
Construction work in progress
    511,864       1,256,311  
 
           
Total property, plant, and equipment
    13,731,702       13,524,984  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    61,257       59,628  
Nuclear decommissioning trusts, at fair value
    475,516       489,795  
Miscellaneous property and investments
    70,028       69,749  
 
           
Total other property and investments
    606,801       619,172  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    412,681       387,447  
Prepaid pension costs
    150,777       132,643  
Other regulatory assets, deferred
    752,469       750,492  
Other deferred charges and assets
    224,551       198,582  
 
           
Total deferred charges and other assets
    1,540,478       1,469,164  
 
           
Total Assets
  $ 17,639,475     $ 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 June 30,     At December 31,  
Liabilities and Stockholder’s Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 300,000     $ 100,000  
Notes payable
    59,997        
Accounts payable —
               
Affiliated
    208,729       194,675  
Other
    197,549       328,400  
Customer deposits
    86,716       86,975  
Accrued taxes —
               
Accrued income taxes
    1,686       14,789  
Other accrued taxes
    75,017       31,918  
Accrued interest
    66,757       65,455  
Accrued vacation pay
    44,415       44,751  
Accrued compensation
    52,176       71,286  
Liabilities from risk management activities
    32,097       37,844  
Over recovered regulatory clause revenues
    103,103       181,565  
Other current liabilities
    53,495       40,020  
 
           
Total current liabilities
    1,281,737       1,197,678  
 
           
Long-term Debt
    5,882,547       6,082,489  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,400,633       2,293,468  
Deferred credits related to income taxes
    86,888       88,705  
Accumulated deferred investment tax credits
    160,751       164,713  
Employee benefit obligations
    386,697       387,936  
Asset retirement obligations
    504,017       491,007  
Other cost of removal obligations
    690,982       668,151  
Other regulatory liabilities, deferred
    127,646       169,224  
Deferred over recovered regulatory clause revenues
    16,874       22,060  
Other deferred credits and liabilities
    41,088       37,113  
 
           
Total deferred credits and other liabilities
    4,415,576       4,322,377  
 
           
Total Liabilities
    11,579,860       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
    2,135,696       2,119,818  
Retained earnings
    2,021,839       1,900,526  
Accumulated other comprehensive loss
    (4,508 )     (5,383 )
 
           
Total common stockholder’s equity
    5,374,527       5,236,461  
 
           
Total Liabilities and Stockholder’s Equity
  $ 17,639,475     $ 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
SECOND QUARTER 2010 vs. SECOND 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 the effects of the recession, 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$13.6   7.7   $70.1   21.7
 
Alabama Power’s net income after dividends on preferred and preference stock for the second quarter 2010 was $189.9 million compared to $176.3 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 $392.7 million compared to $322.6 million for the corresponding period in 2009. The increases when compared to the corresponding periods in 2009 were primarily due to increases in rates under Rate Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant for environmental costs (Rate CNP Environmental) that took effect January 2010, warmer weather in the second quarter 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 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$102.3   9.2   $220.1   10.1
 
In the second quarter 2010, retail revenues were $1.22 billion compared to $1.12 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $2.40 billion compared to $2.18 billion for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Second Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 1,119.6             $ 2,177.7          
Estimated change in —
                               
Rates and pricing
    66.4       5.9       128.3       5.9  
Sales growth (decline)
    6.4       0.6       8.1       0.4  
Weather
    23.0       2.1       81.1       3.7  
Fuel and other cost recovery
    6.5       0.6       2.7       0.1  
 
Retail – current year
  $ 1,221.9       9.2 %   $ 2,397.9       10.1 %
 
Revenues associated with changes in rates and pricing increased in the second 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 increased in the second quarter 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 18.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales increased 1.4% driven by an increase in demand. Weather-adjusted commercial KWH energy sales decreased 3.0% due to a decline in the number of customers and demand.
Revenues attributable to changes in sales increased year-to-date 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 14.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales increased 2.0% driven by an increase in demand. Weather-adjusted commercial KWH energy sales decreased 2.0% driven by a decline in the number of customers.
Revenues resulting from changes in weather increased in the second quarter and for year-to-date 2010 as a result of warmer weather in the second 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 second quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to increases in fuel costs associated with 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 Natural Disaster Reserve (NDR) customer billing rate as a result of achieving the target reserve balance. 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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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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(16.4)   (10.7)   $(3.3)   (1.0)
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Alabama Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation.
In the second quarter 2010, wholesale revenues from non-affiliates were $137.5 million compared to $153.9 million for the corresponding period in 2009. This decrease was primarily due to 25.2% decrease in KWH sales, partially offset by a 19.5% increase in the price of energy. In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $23.0 million revenue reduction. 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.
For year-to-date 2010, the decrease in wholesale revenues from non-affiliates when compared to the corresponding period in 2009 was not material.
Wholesale Revenues – Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.2)   (0.3)   $13.9   10.1
 
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the second quarter 2010, the decrease in wholesale revenues from affiliates when compared to the corresponding period in 2009 was not material.
For year-to-date 2010, wholesale revenues from affiliates were $150.7 million compared to $136.8 million for the corresponding period in 2009. The increase was primarily due to a 6.2% increase in price and a 3.7% increase in KWH sales.
Other Revenues
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$10.0   24.8   $20.4   25.8
 
In the second quarter 2010, other revenues were $50.5 million compared to $40.5 million for the corresponding period in 2009. This increase was due to a $4.9 million increase in revenues from gas-fueled co-generation steam facilities as a

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
result of greater sales volume; a $3.1 million increase in transmission sales; and a $1.1 million increase in customer charges related to reconnection fees.
For year-to-date 2010, other revenues were $99.5 million compared to $79.1 million for the corresponding period in 2009. This increase was due to a $7.7 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume; a $4.5 million increase in transmission sales; a $1.7 million increase in customer charges related to reconnection and late fees; a $1.2 million increase in pole attachment rentals; and a $1.1 million increase in miscellaneous service revenues.
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
                                 
    Second Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Second Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
 
Fuel*
  $ 18.6       4.1     $ 24.4       2.6  
Purchased power – non-affiliates
    (13.5 )     (51.3 )     (11.1 )     (26.6 )
Purchased power – affiliates
    (4.5 )     (8.0 )     5.6       5.7  
                         
Total fuel and purchased power expenses
  $ 0.6             $ 18.9          
                         
*   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 second quarter and year-to-date 2010, the increase in total fuel and purchased power expenses, when compared to the corresponding periods 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.
Details of Alabama Power’s cost of generation and purchased power are as follows:
                                                 
    Second Quarter   Second 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
    2.82       2.78       1.4       2.81       2.85       (1.4 )
Purchased power
    6.19       6.01       3.0       6.65       6.06       9.7  
 
In the second quarter and year-to-date 2010, the increase in fuel expense, when compared to the corresponding periods in 2009, was not material.
Non-Affiliates
In the second quarter 2010, purchased power expense from non-affiliates was $12.7 million compared to $26.2 million for the corresponding period in 2009. This decrease was primarily related to a 53.3% decrease in the amount of energy purchased.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, purchased power expense from non-affiliates was $30.6 million compared to $41.7 million for the corresponding period in 2009. This decrease was related to a 38.2% decrease in the amount of energy purchased, partially offset by an 18.9% increase in the average cost per KWH.
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 second quarter 2010, the decrease in purchased power expense from affiliates when compared to the corresponding period in 2009 was not material. For year-to-date 2010, the increase in purchased power expense from affiliates when compared to the corresponding period in 2009 was not material.
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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$30.5   11.0   $64.4   11.6
 
In the second quarter 2010, other operations and maintenance expenses were $308.8 million compared to $278.3 million for the corresponding period in 2009. Steam production expenses increased $11.0 million due to environmental mandates (which are offset by revenues associated with Rate CNP Environmental) and maintenance costs related to increases in labor. Administrative and general expenses increased $10.5 million related to increases in affiliated service companies’ expenses and the injuries and damages reserve. Nuclear production expenses increased $4.7 million due to maintenance costs related to increases in labor.
For year-to-date 2010, other operations and maintenance expenses were $619.6 million compared to $555.2 million for the corresponding period in 2009. Steam production expenses increased $36.1 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 $22.7 million due to increases in affiliated service companies’ expenses, the injuries and damages reserve, property insurance expenses, and labor, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $4.0 million due to maintenance costs related to increases in labor.
Depreciation and Amortization
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$25.8   20.4   $27.7   10.3
 
In the second quarter 2010, depreciation and amortization was $152.3 million compared to $126.5 million for the corresponding period in 2009. This increase was due to additions of property, plant, and equipment primarily related to steam power, environmental mandates (which are offset by revenues associated with Rate CNP Environmental), and transmission projects.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, depreciation and amortization was $297.6 million compared to $269.9 million for the corresponding period in 2009. This increase was due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.
Allowance for Funds Used During Construction
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(12.0)   (62.7)   $(15.4)   (43.2)
 
In the second quarter 2010, AFUDC equity was $7.1 million compared to $19.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $20.4 million compared to $35.8 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 and general plant projects.
Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$13.5   12.8   $50.8   26.7
 
In the second quarter 2010, income taxes were $118.9 million compared to $105.4 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $241.1 million compared to $190.3 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. Recessionary conditions have impacted sales; 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.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of 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 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 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. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. 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 June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new short-term standard. 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.
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,

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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, the final regulation could significantly alter the options available for beneficial reuse. 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.
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 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 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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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC and Alabama PSC Matters
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 June 30, 2010 totaled $98.8 million as compared to $199.6 million at December 31, 2009. These over recovered fuel costs at June 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. At June 30, 2010, Alabama Power had an accumulated balance of $77.3 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred.
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 rules of the FERC provide that if a request for rehearing is not acted upon within 30 days, it is deemed denied. The ultimate outcome of this matter cannot be determined at this time.
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

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. 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.
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 extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Alabama Power’s service territory. The ultimate impact of this matter cannot be determined at this time.
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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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Alabama Power’s financial condition remained stable at June 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 $497.7 million for the first six months of 2010, compared to $540.1 million for the corresponding period in 2009. The $42.4 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 increases in net income and deferred income taxes. Net cash used for investing activities totaled $546.5 million in the first six months of 2010 primarily due to gross property additions related to steam generation equipment and construction payables. Net cash used for financing activities totaled $219.2 million for the first six months of 2010, compared to $252.3 million provided in the corresponding period in 2009. The $471.5 million decrease is primarily due to fewer issuances of securities and an increase in notes payable. 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 six months of 2010 include increases of $206.7 million in total property, plant, and equipment primarily due to increases in environmental-related equipment and nuclear fuel; $107.2 million in accumulated deferred income taxes; $77.1 million in prepaid expenses; $44.2 million in customer accounts receivable; $31.7 million in unbilled revenues; and $26.0 million in other deferred charges and assets.
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 $300 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 June 30, 2010 cash and cash equivalents of approximately $100 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $333 million expire in 2010, $173 million expire in 2011, and $765 million expire in 2012. Of the credit arrangements that expire in 2010, $333 million contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama Power’s commercial paper borrowings and $744 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to June 30, 2010, Alabama Power renewed a $200 million credit agreement which contains a provision allowing a one-year term loan executable at expiration and extended the expiration date to 2011. 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 June 30, 2010, Alabama Power had $60 million of commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $2 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $336 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.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Alabama Power’s market risk exposure relative to interest rate changes for the second 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.
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 second 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 six months ended June 30, 2010 were as follows:
                 
    Second Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (67 )   $ (44 )
Contracts realized or settled
    20       34  
Current period changes(a)
    2       (35 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (45 )   $ (45 )
 
(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 six months ended June 30, 2010 was an increase of $22 million and a decrease of $1 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 June 30, 2010, Alabama Power had a net hedge volume of 31 million mmBtu with a weighted average contract cost of approximately $1.47 per mmBtu above market prices, compared to 32 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $2.07 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 six months ended June 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:
                                 
    June 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (45 )     (32 )     (13 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (45 )   $ (32 )   $ (13 )   $  
 
Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and 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
Alabama Power did not issue or redeem any securities during the six months ended June 30, 2010.
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 Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 1,826,411     $ 1,682,225     $ 3,617,985     $ 3,274,620  
Wholesale revenues, non-affiliates
    88,605       96,570       198,229       192,556  
Wholesale revenues, affiliates
    11,863       29,623       26,274       44,833  
Other revenues
    72,626       65,896       141,182       128,146  
 
                       
Total operating revenues
    1,999,505       1,874,314       3,983,670       3,640,155  
 
                       
Operating Expenses:
                               
Fuel
    757,380       652,889       1,514,881       1,253,379  
Purchased power, non-affiliates
    83,843       70,817       165,541       132,770  
Purchased power, affiliates
    132,061       172,418       293,998       369,641  
Other operations and maintenance
    399,972       353,562       789,253       744,055  
Depreciation and amortization
    130,046       175,080       244,228       342,191  
Taxes other than income taxes
    85,166       81,008       165,640       157,256  
 
                       
Total operating expenses
    1,588,468       1,505,774       3,173,541       2,999,292  
 
                       
Operating Income
    411,037       368,540       810,129       640,863  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    35,923       22,313       70,655       43,067  
Interest income
    382       (197 )     795       1,033  
Interest expense, net of amounts capitalized
    (87,333 )     (99,425 )     (180,322 )     (197,815 )
Other income (expense), net
    (1,665 )     2,531       (7,213 )     (4,189 )
 
                       
Total other income and (expense)
    (52,693 )     (74,778 )     (116,085 )     (157,904 )
 
                       
Earnings Before Income Taxes
    358,344       293,762       694,044       482,959  
Income taxes
    115,810       99,682       209,182       162,310  
 
                       
Net Income
    242,534       194,080       484,862       320,649  
Dividends on Preferred and Preference Stock
    4,346       4,346       8,691       8,691  
 
                       
Net Income After Dividends on Preferred and Preference Stock
  $ 238,188     $ 189,734     $ 476,171     $ 311,958  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred and Preference Stock
  $ 238,188     $ 189,734     $ 476,171     $ 311,958  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(11), $(905), $(6), and $275, respectively
    (17 )     (1,435 )     (9 )     435  
Reclassification adjustment for amounts included in net income, net of tax of $1,959, $2,427, $3,757, and $4,170, respectively
    3,105       3,848       5,956       6,611  
 
                       
Total other comprehensive income (loss)
    3,088       2,413       5,947       7,046  
 
                       
Comprehensive Income
  $ 241,276     $ 192,147     $ 482,118     $ 319,004  
 
                       
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 Six Months  
    Ended June 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 484,862     $ 320,649  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    325,760       402,086  
Deferred income taxes
    85,220       54,721  
Deferred revenues
    (42,679 )     (20,929 )
Deferred expenses
    17,653       20,523  
Allowance for equity funds used during construction
    (70,655 )     (43,067 )
Pension, postretirement, and other employee benefits
    (10,197 )     (11,543 )
Hedge settlements
          (16,167 )
Insurance cash surrender value
          23,041  
Other, net
    (26,623 )     19,094  
Changes in certain current assets and liabilities —
               
-Receivables
    (146,893 )     (126,080 )
-Fossil fuel stock
    59,474       (222,837 )
-Prepaid income taxes
    12,115       (20,298 )
-Other current assets
    (9,879 )     (14,914 )
-Accounts payable
    80,057       120,228  
-Accrued taxes
    (104,101 )     (74,291 )
-Accrued compensation
    13,061       (103,764 )
-Other current liabilities
    26,458       31,345  
 
           
Net cash provided from operating activities
    693,633       337,797  
 
           
Investing Activities:
               
Property additions
    (1,112,468 )     (1,208,114 )
Distribution of restricted cash from pollution control revenue bonds
          15,566  
Nuclear decommissioning trust fund purchases
    (431,844 )     (699,359 )
Nuclear decommissioning trust fund sales
    404,504       664,633  
Nuclear decommissioning trust securities lending collateral
    23,878       31,264  
Cost of removal, net of salvage
    (29,769 )     (33,041 )
Change in construction payables, net of joint owner portion
    22,584       103,558  
Other investing activities
    4,667       12,646  
 
           
Net cash used for investing activities
    (1,118,448 )     (1,112,847 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (8,033 )     114,439  
Proceeds —
               
Capital contributions from parent company
    569,709       602,968  
Senior notes issuances
    950,000       500,000  
Other long-term debt issuances
          750  
Redemptions —
               
Senior notes
    (601,400 )     (151,928 )
Other long-term debt
    (2,500 )      
Payment of preferred and preference stock dividends
    (8,700 )     (8,758 )
Payment of common stock dividends
    (410,000 )     (369,450 )
Other financing activities
    (13,964 )     (7,963 )
 
           
Net cash provided from financing activities
    475,112       680,058  
 
           
Net Change in Cash and Cash Equivalents
    50,297       (94,992 )
Cash and Cash Equivalents at Beginning of Period
    14,309       132,739  
 
           
Cash and Cash Equivalents at End of Period
  $ 64,606     $ 37,747  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $26,404 and $18,986 capitalized for 2010 and 2009, respectively)
  $ 172,335     $ 167,890  
Income taxes (net of refunds)
  $ 95,814     $ 79,141  
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 June 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 64,606     $ 14,309  
Receivables —
               
Customer accounts receivable
    596,015       486,885  
Unbilled revenues
    224,951       172,035  
Under recovered regulatory clause revenues
    177,265       291,837  
Joint owner accounts receivable
    137,400       146,932  
Other accounts and notes receivable
    61,281       62,758  
Affiliated companies
    32,906       11,775  
Accumulated provision for uncollectible accounts
    (10,130 )     (9,856 )
Fossil fuel stock, at average cost
    666,792       726,266  
Materials and supplies, at average cost
    362,247       362,803  
Vacation pay
    74,291       74,566  
Prepaid income taxes
    108,523       132,668  
Other regulatory assets, current
    80,500       76,634  
Other current assets
    49,415       62,651  
 
           
Total current assets
    2,626,062       2,612,263  
 
           
Property, Plant, and Equipment:
               
In service
    25,931,241       25,120,034  
Less accumulated provision for depreciation
    9,731,877       9,493,068  
 
           
Plant in service, net of depreciation
    16,199,364       15,626,966  
Nuclear fuel, at amortized cost
    373,327       339,810  
Construction work in progress
    2,732,607       2,521,091  
 
           
Total property, plant, and equipment
    19,305,298       18,487,867  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    67,666       66,106  
Nuclear decommissioning trusts, at fair value
    579,520       580,322  
Miscellaneous property and investments
    38,225       38,516  
 
           
Total other property and investments
    685,411       684,944  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    692,440       608,851  
Deferred under recovered regulatory clause revenues
    479,896       373,245  
Other regulatory assets, deferred
    1,385,830       1,321,904  
Other deferred charges and assets
    197,930       205,492  
 
           
Total deferred charges and other assets
    2,756,096       2,509,492  
 
           
Total Assets
  $ 25,372,867     $ 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 June 30,     At December 31,  
Liabilities and Stockholder’s Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 403,898     $ 253,882  
Notes payable
    315,925       323,958  
Accounts payable —
               
Affiliated
    303,599       238,599  
Other
    659,546       602,003  
Customer deposits
    202,327       200,103  
Accrued taxes —
               
Accrued income taxes
    30,533       548  
Unrecognized tax benefits
    167,618       164,863  
Other accrued taxes
    171,328       290,174  
Accrued interest
    88,719       89,228  
Accrued vacation pay
    55,098       57,662  
Accrued compensation
    58,593       42,756  
Liabilities from risk management activities
    52,390       49,788  
Other cost of removal obligations, current
    108,000       216,000  
Other regulatory liabilities, current
    52,838       99,807  
Other current liabilities
    137,394       84,319  
 
           
Total current liabilities
    2,807,806       2,713,690  
 
           
Long-term Debt
    7,971,643       7,782,340  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    3,527,777       3,389,907  
Deferred credits related to income taxes
    131,218       133,683  
Accumulated deferred investment tax credits
    235,876       242,496  
Employee benefit obligations
    914,733       923,177  
Asset retirement obligations
    694,213       676,705  
Other cost of removal obligations
    119,709       124,662  
Other deferred credits and liabilities
    153,752       139,024  
 
           
Total deferred credits and other liabilities
    5,777,278       5,629,654  
 
           
Total Liabilities
    16,556,727       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
    5,167,490       4,592,350  
Retained earnings
    2,999,105       2,932,934  
Accumulated other comprehensive loss
    (14,885 )     (20,832 )
 
           
Total common stockholder’s equity
    8,550,183       7,902,925  
 
           
Total Liabilities and Stockholder’s Equity
  $ 25,372,867     $ 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
SECOND QUARTER 2010 vs. SECOND 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 the effects of the recession, 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
             
Second Quarter 2010 vs. Second Quarter 2009 Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$48.5
  25.5   $164.2   52.6
 
Georgia Power’s net income after dividends on preferred and preference stock for the second quarter 2010 was $238.2 million compared to $189.7 million for the corresponding period in 2009. Georgia Power’s year-to-date 2010 net income after dividends on preferred and preference stock was $476.2 million compared to $312.0 million for the corresponding period in 2009. These increases were due primarily to higher residential base revenues resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010, and the amortization of the regulatory liability related to other cost of removal obligations that began in July 2009 as authorized by the Georgia PSC. These increases were partially offset by increases in operation and maintenance expenses.
Retail Revenues
             
Second Quarter 2010 vs. Second Quarter 2009 Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$144.2   8.6   $343.4   10.5
 
In the second quarter 2010, retail revenues were $1.8 billion compared to $1.7 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $3.6 billion compared to $3.3 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:
                                 
    Second Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 1,682.2             $ 3,274.6          
Estimated change in —
                               
Rates and pricing
    (25.2 )     (1.5 )     (27.7 )     (0.8 )
Sales growth (decline)
    26.1       1.6       40.1       1.2  
Weather
    29.6       1.8       77.6       2.4  
Fuel cost recovery
    113.7       6.8       253.4       7.7  
 
Retail – current year
  $ 1,826.4       8.7 %   $ 3,618.0       10.5 %
 
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2010 when compared to the corresponding periods in 2009 due to lower contributions from market-driven rates for sales to industrial customers, partially offset by increased recognition of environmental compliance cost recovery revenues in accordance with the 2007 Retail Rate Plan.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2010 when compared to the corresponding periods in 2009. Weather-adjusted residential KWH sales increased 2.0%, weather-adjusted commercial KWH sales decreased 0.1%, and weather-adjusted industrial KWH sales increased 10.4% in the second quarter 2010 when compared to the corresponding period in 2009. Weather-adjusted residential KWH sales increased 1.6%, weather-adjusted commercial KWH sales increased 0.4%, and weather-adjusted industrial KWH sales increased 7.5% year-to-date 2010 when compared to the corresponding period in 2009.
Revenues resulting from changes in weather increased in the second quarter and year-to-date 2010 as a result of warmer weather in the second quarter 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 $113.7 million in the second quarter 2010 and $253.4 million for year-to-date 2010 when compared to the corresponding periods in 2009 due to the increase in the fuel cost recovery rate effective April 1, 2010. See Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters — Fuel Cost Recovery” herein for additional information.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$(8.0)
  (8.2)   $5.6   2.9
 
Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Georgia Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation.
In the second quarter 2010, wholesale revenues from non-affiliates were $88.6 million compared to $96.6 million in the corresponding period in 2009. This decrease was due to a 23.9% decrease in KWH sales due to lower demand because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, wholesale revenues from non-affiliates were $198.2 million compared to $192.6 million in the corresponding period in 2009. This increase was due to higher capacity revenues of $7.9 million related to increased contributions from the environmental control component of market-based wholesale rates, partially offset by an 8.9% decrease in KWH sales due to lower demand because the market cost of available energy was lower than the cost of Georgia Power-owned generation.
Wholesale Revenues – Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$(17.7)   (60.0)   $(18.5)   (41.4)
 
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 second quarter 2010, wholesale revenues from affiliates were $11.9 million compared to $29.6 million for the corresponding period in 2009. For year-to-date 2010, wholesale revenues from affiliates were $26.3 million compared to $44.8 million for the corresponding period in 2009. These decreases were due to a 54.9% decrease and a 37.7% decrease in KWH sales due to lower demand in the second quarter 2010 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$6.7   10.2   $13.1   10.2
 
In the second quarter 2010, other revenues were $72.6 million compared to $65.9 million for the corresponding period in 2009. This increase was primarily due to a $3.4 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies and an increase of $1.3 million in outdoor lighting revenues.
For year-to-date 2010, other revenues were $141.2 million compared to $128.1 million for the corresponding period in 2009. This increase was due to a $6.3 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies, an increase of $1.8 million in pole attachment and equipment rental revenue, and an increase of $1.4 million in outdoor lighting revenues.
Fuel and Purchased Power Expenses
                                 
    Second Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Second Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ 104.5       16.0     $ 261.5       20.9  
Purchased power — non-affiliates
    13.0       18.4       32.7       24.7  
Purchased power — affiliates
    (40.3 )     (23.4 )     (75.6 )     (20.5 )
                     
Total fuel and purchased power expenses
  $ 77.2             $ 218.6          
                     
 
*   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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2010, total fuel and purchased power expenses were $973.3 million compared to $896.1 million in the corresponding period in 2009. This increase was primarily due to a $79.4 million increase in the average cost of fuel and purchased power.
For year-to-date 2010, total fuel and purchased power expenses were $2.0 billion compared to $1.8 billion in the corresponding period in 2009. This increase was due to a $179.5 million increase in the average cost of fossil and nuclear fuel and $39.1 million 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 quarter 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.
Details of Georgia Power’s cost of generation and purchased power are as follows:
                                                 
    Second Quarter   Second 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
    3.75       3.40       10.3       3.76       3.32       13.3  
Purchased power
    5.96       5.63       5.9       6.16       5.99       2.8  
 
In the second quarter 2010, fuel expense was $757.4 million compared to $652.9 million in the corresponding period in 2009. This increase was due to a 10.3% increase in the average cost of fuel per KWH and a 9.5% increase of KWHs generated as a result of higher KWH demand.
For year-to-date 2010, fuel expense was $1.5 billion compared to $1.3 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 9.9% increase of KWHs generated as a result of higher KWH demand.
Non-Affiliates
In the second quarter 2010, purchased power expense from non-affiliates was $83.8 million compared to $70.8 million in the corresponding period in 2009. This increase was due to a 41.3% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, partially offset by an 8.8% decrease in the volume of KWHs purchased.
For year-to-date 2010, purchased power expense from non-affiliates was $165.5 million compared to $132.8 million in the corresponding period in 2009. This increase was due to a 40.5% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, partially offset by a 4.8% decrease in the volume of KWHs 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 second quarter 2010, purchased power expense from affiliates was $132.1 million compared to $172.4 million in the corresponding period in 2009. This decrease was due to a 5.6% decrease in the average cost per KWH purchased following the expiration of a PPA in December 2009 and a 20.5% decrease in the volume of KWHs purchased.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, purchased power expense from affiliates was $294.0 million compared to $369.6 million in the corresponding period in 2009. This decrease was due to a 7.7% decrease in the average cost per KWH purchased and a 12.4% 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.
Other Operations and Maintenance Expenses
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$46.4
  13.1   $45.2   6.1
 
In the second quarter 2010, other operations and maintenance expenses were $400.0 million compared to $353.6 million in the corresponding period in 2009. This increase was due to increases of $29.0 million in power generation, $14.6 million in transmission and distribution, and $5.9 million in customer accounting, service, and sales primarily due to cost containment efforts as a result of the economic conditions in 2009.
For year-to-date 2010, other operations and maintenance expenses were $789.3 million compared to $744.1 million in the corresponding period in 2009. This increase was due to increases of $45.8 million in power generation and $20.1 million in transmission and distribution due to cost containment efforts as a result of the economic conditions in 2009, partially offset by a decrease of $21.4 million in administrative and general expenses primarily due to a charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign their positions effective March 31, 2009.
Depreciation and Amortization
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$(45.0)   (25.7)   $(98.0)   (28.6)
 
In the second quarter 2010, depreciation and amortization was $130.1 million compared to $175.1 million in the corresponding period in 2009. This decrease was due to the amortization of $54 million 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.
For year-to-date 2010, depreciation and amortization was $244.2 million compared to $342.2 million in the corresponding period in 2009. This decrease was due to the amortization of $114.3 million 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.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$4.2   5.1   $8.3   5.3
 
In the second quarter 2010, taxes other than income taxes were $85.2 million compared to $81.0 million in the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $165.6 million compared to $157.3 million in the corresponding period in 2009. These increases were due to higher municipal franchise fees resulting from increased retail revenues in the second quarter and year-to-date 2010.
Allowance for Funds Used During Construction
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$13.6   61.0   $27.6   64.1
 
In the second quarter 2010, AFUDC equity was $35.9 million compared to $22.3 million in the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $70.7 million compared to $43.1 million in the corresponding period in 2009. These increases were due to the increase in construction work in progress balances 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
             
Second Quarter 2010 vs. Second Quarter 2009   Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)   (% change)   (change in millions)   (% change)
$16.1   16.2   $46.9   28.9
 
In the second quarter 2010, income taxes were $115.8 million compared to $99.7 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by increased state investment tax credits and non-taxable AFUDC equity.
For year-to-date 2010, income taxes were $209.2 million compared to $162.3 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, 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 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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Recessionary conditions have impacted sales; the timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Carbon Dioxide Litigation
New York Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — New York Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters — Carbon Dioxide Litigation — New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 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. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Georgia Power in Item 7 of the Form 10-K for 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 December 16, 2010. 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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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 Georgia Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO2) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new short-term standard. 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.
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 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, the final regulation could significantly alter the options available for beneficial reuse. 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

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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.
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 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 ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.
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 June 30, 2010, Georgia Power had a total under recovered fuel cost balance of approximately $657.2 million compared to $665.1 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 Public Interest Advocacy 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.

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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. Through June 30, 2010, Georgia Power had amortized $155.3 million of the regulatory liability and currently expects to amortize the remaining allowed $108 million by December 31, 2010.
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.
 
  §   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.

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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.
Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2010. The final outcome of this matter cannot now be determined.
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, 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. Georgia Power will receive, and will match, $51 million under this agreement.

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Income Tax Matters
Georgia State Income Tax Credits
Georgia Power’s 2005 through 2008 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. On April 30, 2010, the Georgia Department of Revenue filed its notice of appeal with 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.
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 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 separation motions with the Georgia PSC for reconsideration of the order on remand.
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.
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.

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Other Construction
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 resolves 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.
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.
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.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
Georgia Power’s financial condition remained stable at June 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 $693.6 million for the first six months of 2010, compared to $337.8 million for the corresponding period in 2009. The $355.8 million increase in cash provided from operating activities in the first six months of 2010 is primarily due to a $164.2 million increase in net income and fuel inventory reductions in 2010. Net cash used for investing activities totaled $1.1 billion primarily due to gross property additions to utility plant in the first six months of 2010. Net cash provided from financing activities totaled $475.1 million for the first six months of 2010, compared to $680.1 million for the corresponding period in 2009. The $205.0 million decrease is primarily due to higher issuance of short-term debt in 2009 and 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 six months of 2010 include an increase of $817.4 million in total property, plant, and equipment, an increase of $189.3 million in long-term debt to replace short-term debt and provide funds for Georgia Power’s continuous construction program, and an increase in paid in capital of $575.1 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 $403.9 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in 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

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not exceed 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 June 30, 2010 cash and cash equivalents of approximately $64.6 million and unused committed credit arrangements with banks of approximately $1.7 billion. Of the unused credit arrangements, $40.0 million expire in 2010, $555.0 million expire in 2011, and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2010 and 2011, $40.0 million contain provisions allowing two-year term loans executable at expiration and $220.0 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 and approximately $901 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to June 30, 2010, Georgia Power renewed a $40 million credit agreement which contains a provision allowing a two-year term loan executable at expiration and extended the expiration date to 2011. 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 June 30, 2010, Georgia Power had approximately $313 million of commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $29 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.5 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.
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 June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Georgia Power (A2 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of a Southern Company financing subsidiary that issues commercial paper for the benefit of Georgia Power and other Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation

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ratings of Georgia Power (Baa1 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.
Market Price Risk
Georgia Power’s market risk exposure relative to interest rate changes for the second 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 second 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 six months ended June 30, 2010 were as follows:
                 
    Second Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
 
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (125 )   $ (75 )
Contracts realized or settled
    31       50  
Current period changes(a)
    1       (68 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (93 )   $ (93 )
 
 
(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 six months ended June 30, 2010 was an increase of $32 million and a decrease of $18 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 June 30, 2010, Georgia Power had a net hedge volume of 67 million mmBtu with a weighted average contract cost of approximately $1.40 per mmBtu above market prices, compared to 68 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $1.85 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 they are recovered through the fuel cost recovery mechanism.
Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

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The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:
                                 
    June 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (93 )     (52 )     (41 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (93 )   $ (52 )   $ (41 )   $  
 
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Georgia Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In the first quarter 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The 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 the second quarter 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 $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of $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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

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GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 320,109     $ 290,050     $ 624,859     $ 528,441  
Wholesale revenues, non-affiliates
    26,916       22,700       54,830       44,666  
Wholesale revenues, affiliates
    40,873       10,727       50,391       16,087  
Other revenues
    15,273       17,618       29,803       36,185  
 
                       
Total operating revenues
    403,171       341,095       759,883       625,379  
 
                       
Operating Expenses:
                               
Fuel
    195,452       156,195       348,164       271,748  
Purchased power, non-affiliates
    14,409       6,051       21,844       10,489  
Purchased power, affiliates
    11,030       13,240       31,443       28,621  
Other operations and maintenance
    64,606       64,983       135,024       137,474  
Depreciation and amortization
    28,548       23,317       56,619       46,376  
Taxes other than income taxes
    24,060       22,989       49,293       45,437  
 
                       
Total operating expenses
    338,105       286,775       642,387       540,145  
 
                       
Operating Income
    65,066       54,320       117,496       85,234  
Other Income and (Expense):
                               
Allowance for equity funds used during construction
    1,695       5,707       3,080       10,525  
Interest income
    39       85       56       294  
Interest expense, net of amounts capitalized
    (13,137 )     (9,907 )     (24,522 )     (19,739 )
Other income (expense), net
    (351 )     (487 )     (884 )     (1,103 )
 
                       
Total other income and (expense)
    (11,754 )     (4,602 )     (22,270 )     (10,023 )
 
                       
Earnings Before Income Taxes
    53,312       49,718       95,226       75,211  
Income taxes
    19,445       15,899       34,508       23,299  
 
                       
Net Income
    33,867       33,819       60,718       51,912  
Dividends on Preference Stock
    1,550       1,550       3,101       3,101  
 
                       
Net Income After Dividends on Preference Stock
  $ 32,317     $ 32,269     $ 57,617     $ 48,811  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preference Stock
  $ 32,317     $ 32,269     $ 57,617     $ 48,811  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $412, $-, $(542), and $-, respectively
    655             (863 )      
Reclassification adjustment for amounts included in net income, net of tax of $91, $104, $196, and $209, respectively
    146       167       312       334  
 
                       
Total other comprehensive income (loss)
    801       167       (551 )     334  
 
                       
Comprehensive Income
  $ 33,118     $ 32,436     $ 57,066     $ 49,145  
 
                       
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 Six Months  
    Ended June 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 60,718     $ 51,912  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    59,786       48,831  
Deferred income taxes
    6,192       (10,224 )
Allowance for equity funds used during construction
    (3,080 )     (10,525 )
Pension, postretirement, and other employee benefits
    1,487       (597 )
Stock based compensation expense
    813       637  
Hedge settlements
    1,530        
Other, net
    (421 )     (1,759 )
Changes in certain current assets and liabilities —
               
-Receivables
    (61,159 )     (3,606 )
-Fossil fuel stock
    (5,088 )     (50,999 )
-Materials and supplies
    457       (459 )
-Prepaid income taxes
    1,579       416  
-Property damage cost recovery
    22       10,816  
-Other current assets
    1,324       1,319  
-Accounts payable
    21,861       (1,002 )
-Accrued taxes
    26,345       13,591  
-Accrued compensation
    (157 )     (9,347 )
-Other current liabilities
    11,193       10,640  
 
           
Net cash provided from operating activities
    123,402       49,644  
 
           
Investing Activities:
               
Property additions
    (137,133 )     (240,336 )
Investment in restricted cash from pollution control revenue bonds
          (49,188 )
Distribution of restricted cash from pollution control revenue bonds
    6,161       11,417  
Cost of removal, net of salvage
    (8,241 )     (5,439 )
Construction payables
    (18,694 )     9,661  
Payments pursuant to long-term service agreements
    (2,294 )     (3,514 )
Other investing activities
    (187 )     139  
 
           
Net cash used for investing activities
    (160,388 )     (277,260 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (2,692 )     (73,944 )
Proceeds —
               
Common stock issued to parent
    50,000       135,000  
Capital contributions from parent company
    2,167       1,897  
Pollution control revenue bonds
    21,000       130,400  
Senior notes
    175,000       140,000  
Redemptions —
               
Senior notes
    (140,305 )     (722 )
Payment of preference stock dividends
    (3,101 )     (3,101 )
Payment of common stock dividends
    (52,150 )     (44,650 )
Other financing activities
    (2,105 )     (1,547 )
 
           
Net cash provided from financing activities
    47,814       283,333  
 
           
Net Change in Cash and Cash Equivalents
    10,828       55,717  
Cash and Cash Equivalents at Beginning of Period
    8,677       3,443  
 
           
Cash and Cash Equivalents at End of Period
  $ 19,505     $ 59,160  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $1,228 and $4,195 capitalized for 2010 and 2009, respectively)
  $ 19,542     $ 19,502  
Income taxes (net of refunds)
  $ 12,463     $ 25,642  
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 June 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 19,505     $ 8,677  
Restricted cash and cash equivalents
    185       6,347  
Receivables —
               
Customer accounts receivable
    86,031       64,257  
Unbilled revenues
    71,966       60,414  
Under recovered regulatory clause revenues
    12,961       4,285  
Other accounts and notes receivable
    10,763       4,107  
Affiliated companies
    18,175       7,503  
Accumulated provision for uncollectible accounts
    (1,983 )     (1,913 )
Fossil fuel stock, at average cost
    187,898       183,619  
Materials and supplies, at average cost
    43,113       38,478  
Other regulatory assets, current
    19,167       19,172  
Prepaid expenses
    12,423       44,760  
Other current assets
    971       3,634  
 
           
Total current assets
    481,175       443,340  
 
           
Property, Plant, and Equipment:
               
In service
    3,537,498       3,430,503  
Less accumulated provision for depreciation
    1,024,948       1,009,807  
 
           
Plant in service, net of depreciation
    2,512,550       2,420,696  
Construction work in progress
    182,235       159,499  
 
           
Total property, plant, and equipment
    2,694,785       2,580,195  
 
           
Other Property and Investments
    16,112       15,923  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    44,523       39,018  
Other regulatory assets, deferred
    212,385       190,971  
Other deferred charges and assets
    26,741       24,160  
 
           
Total deferred charges and other assets
    283,649       254,149  
 
           
Total Assets
  $ 3,475,721     $ 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 June 30,     At December 31,  
Liabilities and Stockholder’s Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 110,000     $ 140,000  
Notes payable
    86,041       90,331  
Accounts payable —
               
Affiliated
    71,971       47,421  
Other
    62,045       80,184  
Customer deposits
    34,730       32,361  
Accrued taxes —
               
Accrued income taxes
    15,911       1,955  
Other accrued taxes
    19,521       7,297  
Accrued interest
    11,111       10,222  
Accrued compensation
    9,180       9,337  
Other regulatory liabilities, current
    27,311       22,416  
Liabilities from risk management activities
    9,506       9,442  
Other current liabilities
    16,947       20,092  
 
           
Total current liabilities
    474,274       471,058  
 
           
Long-term Debt
    1,063,618       978,914  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    307,752       297,405  
Accumulated deferred investment tax credits
    8,881       9,652  
Employee benefit obligations
    109,924       109,271  
Other cost of removal obligations
    194,244       191,248  
Other regulatory liabilities, deferred
    41,622       41,399  
Other deferred credits and liabilities
    115,065       92,370  
 
           
Total deferred credits and other liabilities
    777,488       741,345  
 
           
Total Liabilities
    2,315,380       2,191,317  
 
           
Preference Stock
    97,998       97,998  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - June 30, 2010: 3,642,717 shares
               
- December 31, 2009: 3,142,717 shares
    303,060       253,060  
Paid-in capital
    537,712       534,577  
Retained earnings
    224,584       219,117  
Accumulated other comprehensive loss
    (3,013 )     (2,462 )
 
           
Total common stockholder’s equity
    1,062,343       1,004,292  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,475,721     $ 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
SECOND QUARTER 2010 vs. SECOND 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 the effects of the recession, 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
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$-   N/M   $8.8   18.0
 
N/M-Not Meaningful
Gulf Power’s net income after dividends on preference stock for the second quarter 2010 was $32.3 million compared to $32.3 million for the corresponding period in 2009. Gulf Power’s net income after dividends on preference stock for year-to-date 2010 was $57.6 million compared to $48.8 million for the corresponding period in 2009. The increase was primarily due to significantly colder weather in the first quarter 2010, partially offset by a decline in sales.
Retail Revenues
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$30.0   10.4   $96.5   18.2
 
In the second quarter 2010, retail revenues were $320.1 million compared to $290.1 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $624.9 million compared to $528.4 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:
                                 
    Second Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 290.1             $ 528.4          
Estimated change in –
                               
Rates and pricing
    16.2       5.6       33.8       6.4  
Sales growth (decline)
    (0.7 )     (0.2 )     (3.6 )     (0.7 )
Weather
    (1.0 )     (0.3 )     11.9       2.2  
Fuel and other cost recovery
    15.5       5.3       54.4       10.3  
 
Retail – current year
  $ 320.1       10.4 %   $ 624.9       18.2 %
         
Revenues associated with changes in rates and pricing increased in the second 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 decreased in the second quarter 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers decreased 4.5% due to decreased customer demand. Weather-adjusted KWH energy sales to residential and commercial customers remained relatively flat.
Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers and weather-adjusted KWH energy sales to commercial customers decreased 3.7% and 1.4%, respectively, due to decreased customer demand. Weather-adjusted KWH energy sales to residential customers remained relatively flat.
Revenues attributable to changes in weather decreased in the second quarter 2010 when compared to the corresponding period in 2009 due to less favorable weather in the second quarter 2010.
Revenues attributable to changes in weather increased year-to-date 2010 when compared to the corresponding period for 2009 due to significantly colder weather in the first quarter 2010.
Fuel and other cost recovery revenues increased in the second 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 second 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 Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$4.2   18.6   $10.1   22.8
 
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.
In the second quarter 2010, wholesale revenues from non-affiliates were $26.9 million compared to $22.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 8.4% increase in KWH sales to serve customer demand and a 6.8% increase in price related to energy rates.
For year-to-date 2010, wholesale revenues from non-affiliates were $54.8 million compared to $44.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 13.9% increase in KWH sales to serve weather-related increases in customer demand and a 10.5% increase in price related to energy rates.
Wholesale Revenues – Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$30.2   281.0   $34.3   213.2
 
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.
In the second quarter 2010, wholesale revenues from affiliates were $40.9 million compared to $10.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 233.6% increase in KWH sales to serve customer demand and a 14.2% increase in price related to energy rates.
For year-to-date 2010, wholesale revenues from affiliates were $50.4 million compared to $16.1 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 171.7% increase in KWH sales to serve customer demand and a 15.3% increase in price related to energy rates.
Other Revenues
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(2.3)   (13.3)   $(6.4)   (17.6)
 
In the second quarter 2010, other revenues were $15.3 million compared to $17.6 million for the corresponding period in 2009. The decrease was primarily due to a $2.5 million decrease in revenues from other energy services.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2010, other revenues were $29.8 million compared to $36.2 million for the corresponding period in 2009. The decrease was primarily due to a $7.7 million decrease in revenues from other energy services, partially offset by higher franchise fees of $1.4 million.
The decreased revenues from other energy services did not have a material impact on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income.
Fuel and Purchased Power Expenses
                                 
    Second Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Second Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel*
  $ 39.2       25.1     $ 76.4       28.1  
Purchased power – non-affiliates
    8.4       138.1       11.4       108.3  
Purchased power – affiliates
    (2.2 )     (16.7 )     2.8       9.9  
                       
Total fuel and purchased power expenses
  $ 45.4             $ 90.6          
                       
 
*   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 second quarter 2010, total fuel and purchased power expenses were $220.9 million compared to $175.5 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $58.4 million increase related to total KWHs generated and purchased, partially offset by a $13.0 million decrease in the average cost of purchased power.
For year-to-date 2010, total fuel and purchased power expenses were $401.4 million compared to $310.8 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $72.3 million increase related to total KWHs generated and purchased and an $18.3 million increase as a result of an increase in the average cost of fuel.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Fuel Cost Recovery” herein for additional information.
Details of Gulf Power’s cost of generation and purchased power are as follows:
                                                 
    Second Quarter   Second 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
    4.93       4.45       10.79       5.01       4.39       14.12  
Purchased power
    4.37       6.71       (34.87 )     4.77       5.87       (18.74 )
 
In the second quarter 2010, fuel expense was $195.4 million compared to $156.2 million for the corresponding period in 2009. The increase was primarily due to a 15.1% increase in the average cost of coal, partially offset by a 2.7% decrease in KWHs generated.

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For year-to-date 2010, fuel expense was $348.1 million compared to $271.7 million for the corresponding period in 2009. The increase was primarily due to a 19.8% increase in the average cost of coal, a 6.5% increase in the average cost of natural gas prices, and a 1.2% increase in KWHs generated as a result of increased demand.
Non-Affiliates
In the second quarter 2010, purchased power expense from non-affiliates was $14.4 million compared to $6.0 million for the corresponding period in 2009. The increase was primarily due to a 942.1% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the third quarter 2009, partially offset by a 44.1% decrease in the average cost per KWH purchased.
For year-to-date 2010, purchased power expense from non-affiliates was $21.9 million compared to $10.5 million for the corresponding period in 2009. The increase was primarily due to a 510.3% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the third quarter 2009, partially offset by a 20.7% 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 the availability of Southern Company system generation.
Affiliates
In the second quarter 2010, purchased power expense from affiliates was $11.0 million compared to $13.2 million for the corresponding period in 2009. The decrease was primarily due to a 26.8% decrease in average cost per KWH purchased, partially offset by a 15.3% increase in the volume of KWHs purchased from lower-priced Power Pool resources.
For year-to-date 2010, purchased power expense from affiliates was $31.4 million compared to $28.6 million for the corresponding period in 2009. The increase was primarily due to a 37.3% increase in the volume of KWHs purchased, partially offset by a 19.2% decrease in the average cost per KWH purchased from lower-priced Power Pool resources.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(0.4)   (0.6)   $(2.5)   (1.8)
 
In the second quarter 2010, other operations and maintenance expenses were $64.6 million compared to $65.0 million for the corresponding period in 2009. For year-to-date 2010, other operations and maintenance expenses were $135.0 million compared to $137.5 million for the corresponding period in 2009. These decreases were primarily due to decreases in storm recovery costs and expenses from other energy services. The decreases were partially offset by increases in maintenance expenses, labor, and benefits expenses.

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Depreciation and Amortization
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$5.2   22.4   $10.2   22.1
 
In the second quarter 2010, depreciation and amortization was $28.5 million compared to $23.3 million for the corresponding period in 2009.
For year-to-date 2010, depreciation and amortization was $56.6 million compared to $46.4 million for the corresponding period in 2009. These increases were primarily due to the addition of an environmental control project at Plant Crist in December 2009 and other net additions to generation and distribution facilities.
Taxes Other Than Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$1.1   4.7   $3.9   8.5
 
In the second quarter 2010, taxes other than income taxes were $24.1 million compared to $23.0 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $49.3 million compared to $45.4 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 Funds Used During Construction
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(4.0)   (70.3)   $(7.4)   (70.7)
 
In the second quarter 2010, AFUDC equity was $1.7 million compared to $5.7 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $3.1 million compared to $10.5 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.
Interest Expense, Net of Amounts Capitalized
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$3.2   32.6   $4.7   24.2
 
In the second quarter 2010, interest expense, net of amounts capitalized was $13.1 million compared to $9.9 million for the corresponding period in 2009. For year-to-date 2010, interest expense, net of amounts capitalized was $24.5 million compared to $19.8 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 to 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.

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Income Taxes
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$3.5   22.3   $11.2   48.1
 
In the second quarter 2010, income taxes were $19.4 million compared to $15.9 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $34.5 million compared to $23.3 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. Recessionary conditions have impacted sales; 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.
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 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 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

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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. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. 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 June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO2, including the establishment of a new short-term standard. 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 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.

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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 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, the final regulation could significantly alter the options available for beneficial reuse. 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.
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 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 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 Fuel Cost Recovery
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 the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.
Under recovered fuel costs at June 30, 2010 totaled $11.2 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

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significant effect on Gulf Power’s revenues or net income, but will affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.
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 $600 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 expected to be held with the Mississippi PSC by late 2010. 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. Gulf Power will receive, and will match, $15.5 million under this agreement.

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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 extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Gulf Power’s service territory. The ultimate impact of this matter cannot be determined at this time.
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.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Gulf Power’s financial condition remained stable at June 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 $123.4 million for the first six months of 2010 compared to $49.6 million for the corresponding period in 2009. The $73.8 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 increases in deferred income taxes, and affiliated payables. The increase was partially offset by a decrease in collections attributable to regulatory fuel clause revenues. Net cash used for

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investing activities totaled $160.4 million in the first six months of 2010 compared to $277.3 million for the corresponding period in 2009. The $116.9 million decrease was primarily due to a $109.2 million decrease in gross property additions. Net cash provided from financing activities totaled $47.8 million for the first six months of 2010, compared to $283.3 million for the corresponding period in 2009. The $235.5 million decrease was primarily due to the redemption of senior notes in 2010 and the higher issuance of pollution control bonds in 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 six months of 2010 include a net increase of $114.6 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of common stock to Southern Company for $50 million; a decrease of $32.3 million in prepaid expenses, primarily due to a planned inspection under a long-term service agreement, and a decrease in PPA deferred capacity expense due to seasonality; a net decrease of $30.0 million in securities due within one year; and an increase in other regulatory assets, deferred and other deferred credits and liabilities of $21.4 million and $22.7 million, respectively, primarily due to an increase in PPA deferred capacity expense.
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 $110 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; 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.
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 June 30, 2010 cash and cash equivalents of approximately $19.5 million and unused committed credit arrangements with banks of $220 million. Of the unused credit arrangements, $80 million expire in 2010 and $155 million expire in 2011. Of these credit arrangements, $205 million contain provisions allowing one-year term loans executable at expiration. Subsequent to June 30, 2010, Gulf Power increased its existing lines of credit by $15 million with an expiration of 2011. 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. All of these facilities contain provisions allowing one-year term loans executable at expiration. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements”

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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 June 30, 2010, Gulf Power had approximately $86 million of commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.
Credit Rating Risk
Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $127 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $566 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.
On 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 preference stock decreased from A- to BBB+. These ratings are not applicable to the collateral requirements described above.
On June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Gulf Power (A2 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of a Southern Company financing subsidiary that issues commercial paper for the benefit of Gulf Power and other Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation ratings of Gulf Power (Baa1 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.
Market Price Risk
Gulf Power’s market risk exposure relative to interest rate changes for the second 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 second quarter 2010 when compared with the December 31, 2009 reporting period.

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GULF POWER COMPANY
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 six months ended June 30, 2010 were as follows:
                 
    Second Quarter   Year-to-Date
    2010   2010
    Changes   Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (21 )   $ (14 )
Contracts realized or settled
    6       10  
Current period changes(a)
          (11 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (15 )   $ (15 )
 
     
(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 six months ended June 30, 2010 was an increase of $6 million and a decrease of $1 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 June 30, 2010, Gulf Power had a net hedge volume of 9 million mmBtu with a weighted average contract cost of approximately $1.61 per mmBtu above market prices, compared to 10 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $2.09 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.
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 six months ended June 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.
The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:
                                 
    June 30, 2010
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (15 )     (10 )     (5 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (15 )   $ (10 )   $ (5 )   $  
 

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and 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 six 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. Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The 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 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 Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Operating Revenues:
                               
Retail revenues
  $ 203,094     $ 201,132     $ 389,681     $ 376,867  
Wholesale revenues, non-affiliates
    66,201       73,693       145,090       153,847  
Wholesale revenues, affiliates
    3,936       7,963       18,611       17,381  
Other revenues
    3,590       3,893       7,077       7,309  
 
                       
Total operating revenues
    276,821       286,681       560,459       555,404  
 
                       
Operating Expenses:
                               
Fuel
    103,575       125,832       234,372       245,797  
Purchased power, non-affiliates
    1,498       2,873       5,119       5,708  
Purchased power, affiliates
    34,490       21,595       49,211       43,400  
Other operations and maintenance
    71,764       61,601       139,102       121,362  
Depreciation and amortization
    18,786       17,660       37,461       35,675  
Taxes other than income taxes
    17,173       16,221       35,633       31,145  
 
                       
Total operating expenses
    247,286       245,782       500,898       483,087  
 
                       
Operating Income
    29,535       40,899       59,561       72,317  
Other Income and (Expense):
                               
Interest income
    40       163       73       795  
Interest expense, net of amounts capitalized
    (5,946 )     (6,254 )     (12,125 )     (11,016 )
Other income (expense), net
    1,152       1,136       2,701       2,765  
 
                       
Total other income and (expense)
    (4,754 )     (4,955 )     (9,351 )     (7,456 )
 
                       
Earnings Before Income Taxes
    24,781       35,944       50,210       64,861  
Income taxes
    9,129       13,578       18,872       24,091  
 
                       
Net Income
    15,652       22,366       31,338       40,770  
Dividends on Preferred Stock
    433       433       866       866  
 
                       
Net Income After Dividends on Preferred Stock
  $ 15,219     $ 21,933     $ 30,472     $ 39,904  
 
                       
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                                 
    For the Three Months     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (in thousands)     (in thousands)  
Net Income After Dividends on Preferred Stock
  $ 15,219     $ 21,933     $ 30,472     $ 39,904  
Other comprehensive income (loss):
                               
Qualifying hedges:
                               
Changes in fair value, net of tax of $(8), $(139), $4, and $27, respectively
    (14 )     (224 )     6       44  
 
                       
Comprehensive Income
  $ 15,205     $ 21,709     $ 30,478     $ 39,948  
 
                       
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 Six Months  
    Ended June 30,  
    2010     2009  
    (in thousands)  
Operating Activities:
               
Net income
  $ 31,338     $ 40,770  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    40,362       39,202  
Deferred income taxes
    (7,593 )     (11,019 )
Pension, postretirement, and other employee benefits
    3,638       2,852  
Stock based compensation expense
    917       747  
Generation construction screening costs
    (50,554 )     (14,049 )
Other, net
    (1,150 )     2,092  
Changes in certain current assets and liabilities —
               
-Receivables
    (8,183 )     (20,557 )
-Under recovered regulatory clause revenues
          33,831  
-Fossil fuel stock
    (3,557 )     (44,024 )
-Materials and supplies
    (4,167 )     (1,464 )
-Prepaid income taxes
          (446 )
-Other current assets
    (8,330 )     (12,644 )
-Other accounts payable
    6,462       (14,103 )
-Accrued taxes
    (3,576 )     (14,243 )
-Accrued compensation
    (4,452 )     (12,990 )
-Over recovered regulatory clause revenues
    2,106        
-Other current liabilities
    1,591       2,260  
 
           
Net cash used for operating activities
    (5,148 )     (23,785 )
 
           
Investing Activities:
               
Property additions
    (55,263 )     (50,943 )
Cost of removal, net of salvage
    (5,749 )     (7,287 )
Construction payables
    8,781       (4,709 )
Other investing activities
    (6,227 )     (1,412 )
 
           
Net cash used for investing activities
    (58,458 )     (64,351 )
 
           
Financing Activities:
               
Increase in notes payable, net
    38,993       20,501  
Proceeds —
               
Capital contributions from parent company
    1,696       2,101  
Senior notes issuances
          125,000  
Redemptions —
               
Capital leases
    (652 )      
Senior notes
          (40,000 )
Payment of preferred stock dividends
    (866 )     (866 )
Payment of common stock dividends
    (34,300 )     (34,250 )
Other financing activities
    (8 )     (1,720 )
 
           
Net cash provided from financing activities
    4,863       70,766  
 
           
Net Change in Cash and Cash Equivalents
    (58,743 )     (17,370 )
Cash and Cash Equivalents at Beginning of Period
    65,025       22,413  
 
           
Cash and Cash Equivalents at End of Period
  $ 6,282     $ 5,043  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $167 and $117 capitalized for 2010 and 2009, respectively)
  $ 11,022     $ 8,873  
Income taxes (net of refunds)
  $ 9,233     $ 27,149  
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 June 30,     At December 31,  
Assets   2010     2009  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 6,282     $ 65,025  
Receivables —
               
Customer accounts receivable
    39,329       36,766  
Unbilled revenues
    32,487       27,168  
Other accounts and notes receivable
    6,454       11,337  
Affiliated companies
    18,399       13,215  
Accumulated provision for uncollectible accounts
    (735 )     (940 )
Fossil fuel stock, at average cost
    130,794       127,237  
Materials and supplies, at average cost
    31,960       27,793  
Other regulatory assets, current
    60,475       53,273  
Prepaid income taxes
    33,020       32,237  
Other current assets
    15,884       12,625  
 
           
Total current assets
    374,349       405,736  
 
           
Property, Plant, and Equipment:
               
In service
    2,346,147       2,316,494  
Less accumulated provision for depreciation
    967,537       950,373  
 
           
Plant in service, net of depreciation
    1,378,610       1,366,121  
Construction work in progress
    184,302       48,219  
 
           
Total property, plant, and equipment
    1,562,912       1,414,340  
 
           
Other Property and Investments
    6,413       7,018  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    13,778       8,536  
Other regulatory assets, deferred
    151,580       209,100  
Other deferred charges and assets
    24,378       27,951  
 
           
Total deferred charges and other assets
    189,736       245,587  
 
           
Total Assets
  $ 2,133,410     $ 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 June 30,     At December 31,  
Liabilities and Stockholder’s Equity   2010     2009  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 81,382     $ 1,330  
Notes payable
    38,993        
Accounts payable —
               
Affiliated
    59,056       49,209  
Other
    43,901       38,662  
Customer deposits
    11,852       11,143  
Accrued taxes —
               
Accrued income taxes
    27,463       10,590  
Other accrued taxes
    29,101       49,547  
Accrued interest
    5,764       5,739  
Accrued compensation
    9,333       13,785  
Other regulatory liabilities, current
    5,750       7,610  
Over recovered regulatory clause liabilities
    50,702       48,596  
Liabilities from risk management activities
    22,521       19,454  
Other current liabilities
    24,689       21,142  
 
           
Total current liabilities
    410,507       276,807  
 
           
Long-term Debt
    412,859       493,480  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    222,009       223,066  
Deferred credits related to income taxes
    12,470       13,937  
Accumulated deferred investment tax credits
    12,231       12,825  
Employee benefit obligations
    164,222       161,778  
Other cost of removal obligations
    104,096       97,820  
Other regulatory liabilities, deferred
    55,916       54,576  
Other deferred credits and liabilities
    48,787       47,090  
 
           
Total deferred credits and other liabilities
    619,731       611,092  
 
           
Total Liabilities
    1,443,097       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
    328,395       325,562  
Retained earnings
    291,441       295,269  
Accumulated other comprehensive income (loss)
    6        
 
           
Total common stockholder’s equity
    657,533       658,522  
 
           
Total Liabilities and Stockholder’s Equity
  $ 2,133,410     $ 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
SECOND QUARTER 2010 vs. SECOND 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 the effects of the recession, 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
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
   
(change in millions)   (% change)   (change in millions)   (% change)
$(6.7)   (30.6)   $(9.4)   (23.6)
   
Mississippi Power’s net income after dividends on preferred stock for the second quarter 2010 was $15.2 million compared to $21.9 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for the second quarter 2010 was primarily due to a decrease in wholesale energy revenue from non-affiliate customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation. The decrease in net income after dividends on preferred stock for the second quarter 2010 was partially offset by an increase in territorial base revenue primarily resulting from warmer weather in the second quarter 2010 compared to the second quarter 2009.
Mississippi Power’s net income after dividends on preferred stock for year-to-date 2010 was $30.5 million compared to $39.9 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 revenue from non-affiliate customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses, interest expense, net of amounts capitalized, and depreciation expense. The decrease in net income after dividends on preferred stock for year-to-date 2010 was partially offset by an increase in territorial base revenue primarily resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010 compared to year-to-date 2009.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$2.0   1.0   $12.8   3.4
 
In the second quarter 2010, retail revenues were $203.1 million compared to $201.1 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $389.7 million compared to $376.9 million for the corresponding period in 2009.
Details of the change to retail revenues are as follows:
                                 
    Second Quarter   Year-to-Date
    2010   2010
    (in millions)   (% change)   (in millions)   (% change)
Retail – prior year
  $ 201.1             $ 376.9          
Estimated change in —
                               
Rates and pricing
    0.5       0.2       0.2       0.1  
Sales growth (decline)
    (0.8 )     (0.4 )     (2.0 )     (0.5 )
Weather
    2.3       1.2       9.3       2.4  
Fuel and other cost recovery
                5.3       1.4  
 
Retail – current year
    203.1       1.0       389.7       3.4  
 
Revenues associated with changes in rates and pricing increased in the second quarter 2010 when compared to the corresponding period in 2009 primarily due to an increase of $0.5 million related to the ECO Plan rate.
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 second quarter 2010 when compared to the corresponding period in 2009 primarily due to a decline in residential and commercial customers. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.6% and 4.2%, respectively, primarily due to the declining number of residential and commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 4.8% as a result of increased production for several large industrial customers due to improving economic conditions.
Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009 primarily due to a decline in residential and commercial customers. Weather-adjusted KWH energy sales to residential customers increased 1.6% primarily due to an increase in customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 5.4% primarily due to the declining number of commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 6.0% as a result of increased production for several large industrial customers due to improving economic conditions.
Revenues attributable to changes in weather increased in the second quarter and year-to-date 2010 due to warmer weather in the second quarter 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 had no significant change in the second quarter 2010 when compared to the corresponding period in 2009. Fuel and other cost recovery revenues increased year-to-date 2010 when compared to the corresponding period in 2009 primarily as a result of higher recoverable fuel costs and an increase in revenues related to ad valorem taxes. 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
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(7.5)   (10.2)   $(8.7)   (5.7)
 
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.
In the second quarter 2010, wholesale revenues from non-affiliates were $66.2 million compared to $73.7 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $7.8 million, partially offset by a $0.3 million increase in revenues from customers inside Mississippi Power’s service territory. The $7.8 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $9.0 million decrease in sales volume, partially offset by a $1.1 million increase associated with higher prices, resulting from the higher marginal cost of fuel, and a $0.1 million increase in capacity revenues. The $0.3 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 $0.2 million increase in wholesale base revenues resulting from warmer weather in the second quarter 2010 when compared to the corresponding period in 2009.
For year-to-date 2010, wholesale revenues from non-affiliates were $145.1 million compared to $153.8 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $16.2 million, partially offset by a $7.5 million increase in revenues from customers inside Mississippi Power’s service territory. The $16.2 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to an $18.7 million decrease in sales volume, partially offset by a $2.3 million increase associated with higher prices, resulting from the higher marginal cost of fuel, and a $0.2 million increase in capacity revenues. The $7.5 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $4.3 million increase in fuel revenues and a $3.2 million increase in wholesale base revenues resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding period in 2009.
Wholesale Revenues – Affiliates
             
Second Quarter 2010 vs. Second Quarter 2009
  Year-to-Date 2010 vs. Year-to-Date 2009
 
(change in millions)   (% change)   (change in millions)   (% change)
$(4.1)   (50.6)   $1.2   7.1
   
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

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Table of Contents

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2010, wholesale revenues from affiliates were $3.9 million compared to $8.0 million for the corresponding period in 2009. The decrease was primarily due to a $4.2 million decrease in energy revenues, of which $4.7 million was associated with decreased sales volume, partially offset by an increase of $0.5 million associated with higher prices. Capacity revenues increased $0.1 million.
For year-to-date 2010, wholesale revenues from affiliates were $18.6 million compared to $17.4 million for the corresponding period in 2009. The increase was primarily due to a $0.7 million increase in energy revenues, of which $1.2 million was associated with higher prices, partially offset by a decrease of $0.5 million associated with decreased sales volume. Capacity revenues increased $0.5 million.
Fuel and Purchased Power Expenses
                                 
    Second Quarter 2010   Year-to-Date 2010
    vs.   vs.
    Second Quarter 2009   Year-to-Date 2009
    (change in millions)   (% change)   (change in millions)   (% change)
Fuel
  $ (22.2 )     (17.7 )   $ (11.4 )     (4.6 )
Purchased power – non-affiliates
    (1.4 )     (47.9 )     (0.6 )     (10.3 )
Purchased power – affiliates
    12.9       59.7       5.8       13.4  
                       
Total fuel and purchased power expenses
  $ (10.7 )           $ (6.2 )        
                       
In the second quarter 2010, total fuel and purchased power expenses were $139.6 million compared to $150.3 million for the corresponding period in 2009. The decrease was primarily due to a $17.4 million decrease related to the total KWHs generated and purchased, partially offset by a $6.7 million increase in the cost of fuel and purchased power.
For year-to-date 2010, total fuel and purchased power expenses were $288.7 million compared to $294.9 million for the corresponding period in 2009. The decrease was primarily due to a $5.8 million decrease related to the total KWHs generated and purchased and a $0.4 million decrease in the cost of fuel and purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Retail Regulatory Matters” herein for additional information.
Details of Mississippi Power’s cost of generation and purchased power are as follows:
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    Second Quarter   Second 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
    4.39       4.21       4.3       4.30       4.32       (0.5 )
Purchased power
    3.60       3.36