TEST ONLY
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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 March 31, 2011
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
         
Commission   Registrant, State of Incorporation,   I.R.S. Employer
File Number   Address and Telephone Number   Identification No.
1-3526
  The Southern Company   58-0690070
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    
 
       
1-3164
  Alabama Power Company   63-0004250
 
  (An Alabama Corporation)    
 
  600 North 18th Street    
 
  Birmingham, Alabama 35203    
 
  (205) 257-1000    
 
       
1-6468
  Georgia Power Company   58-0257110
 
  (A Georgia Corporation)    
 
  241 Ralph McGill Boulevard, N.E.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-6526    
 
       
001-31737
  Gulf Power Company   59-0276810
 
  (A Florida Corporation)    
 
  One Energy Place    
 
  Pensacola, Florida 32520    
 
  (850) 444-6111    
 
       
001-11229
  Mississippi Power Company   64-0205820
 
  (A Mississippi Corporation)    
 
  2992 West Beach    
 
  Gulfport, Mississippi 39501    
 
  (228) 864-1211    
 
       
333-98553
  Southern Power Company   58-2598670
 
  (A Delaware Corporation)    
 
  30 Ivan Allen Jr. Boulevard, N.W.    
 
  Atlanta, Georgia 30308    
 
  (404) 506-5000    

 


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     Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
     Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No o (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 March 31, 2011  
The Southern Company
  Par Value $5 Per Share     849,122,723  
Alabama Power Company
  Par Value $40 Per Share     30,537,500  
Georgia Power Company
  Without Par Value     9,261,500  
Gulf Power Company
  Without Par Value     4,142,717  
Mississippi Power Company
  Without Par Value     1,121,000  
Southern Power Company
  Par Value $0.01 Per Share     1,000  
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2


 

INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2011
             
        Page
        Number
DEFINITIONS     5  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION     7  
   
 
       
PART I — FINANCIAL INFORMATION
       
   
 
       
Item 1.  
Financial Statements (Unaudited)
       
Item 2.  
Management’s Discussion and Analysis of Financial Condition and Results of Operations
       
           
        9  
        10  
        11  
        13  
        14  
           
        32  
        32  
        33  
        34  
        36  
           
        49  
        49  
        50  
        51  
        53  
           
        68  
        68  
        69  
        70  
        72  
           
        85  
        85  
        86  
        87  
        89  
           
        106  
        106  
        107  
        108  
        110  
        119  
Item 3.       30  
Item 4.       30  

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 2011
             
        Page
        Number
PART II — OTHER INFORMATION
   
 
       
Item 1.     145
Item 1A.     145
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.     146
      150

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

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DEFINITIONS
(continued)
     
Term   Meaning
SCR
  Selective catalytic reduction
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
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, future earnings, access to sources of capital, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
  the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
 
  current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS audits;
 
  the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
  variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;
 
  available sources and costs of fuels;
 
  effects of inflation;
 
  ability to control costs and avoid cost overruns during the development and construction of facilities;
 
  investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trust funds;
 
  advances in technology;
 
  state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
 
  regulatory approvals and actions related to the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;
 
  regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees;
 
  the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
 
  internal restructuring or other restructuring options that may be pursued;
 
  potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
 
  the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
 
  the ability to obtain new short- and long-term contracts with wholesale customers;
 
  the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
 
  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 filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.

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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

8


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Operating Revenues:
               
Retail revenues
  $ 3,396     $ 3,459  
Wholesale revenues
    449       542  
Other electric revenues
    150       135  
Other revenues
    17       21  
 
           
Total operating revenues
    4,012       4,157  
 
           
Operating Expenses:
               
Fuel
    1,476       1,645  
Purchased power
    100       127  
Other operations and maintenance
    944       908  
Depreciation and amortization
    418       343  
Taxes other than income taxes
    220       212  
 
           
Total operating expenses
    3,158       3,235  
 
           
Operating Income
    854       922  
Other Income and (Expense):
               
Allowance for equity funds used during construction
    35       49  
Interest expense, net of amounts capitalized
    (222 )     (222 )
Other income (expense), net
    2       (2 )
 
           
Total other income and (expense)
    (185 )     (175 )
 
           
Earnings Before Income Taxes
    669       747  
Income taxes
    231       236  
 
           
Consolidated Net Income
    438       511  
Dividends on Preferred and Preference Stock of Subsidiaries
    16       16  
 
           
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries
  $ 422     $ 495  
 
           
Common Stock Data:
               
Earnings per share (EPS) -
               
Basic EPS
  $ 0.50     $ 0.60  
Diluted EPS
  $ 0.49     $ 0.60  
Average number of shares of common stock outstanding (in millions)
               
Basic
    848       823  
Diluted
    854       825  
Cash dividends paid per share of common stock
  $ 0.4550     $ 0.4375  
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 Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Consolidated net income
  $ 438     $ 511  
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    501       422  
Deferred income taxes
    174       107  
Deferred revenues
    (2 )     (20 )
Allowance for equity funds used during construction
    (35 )     (49 )
Pension, postretirement, and other employee benefits
    (11 )     5  
Stock based compensation expense
    21       19  
Generation construction screening costs
          (19 )
Other, net
    (14 )     (37 )
Changes in certain current assets and liabilities —
               
-Receivables
    276       43  
-Fossil fuel stock
    (42 )     133  
-Other current assets
    (77 )     (94 )
-Accounts payable
    (108 )     (100 )
-Accrued taxes
    131       (73 )
-Accrued compensation
    (277 )     (112 )
-Other current liabilities
    23       2  
 
           
Net cash provided from operating activities
    998       738  
 
           
Investing Activities:
               
Property additions
    (1,086 )     (1,054 )
Investment in restricted cash
    (3 )      
Distribution of restricted cash
    61       8  
Nuclear decommissioning trust fund purchases
    (928 )     (238 )
Nuclear decommissioning trust fund sales
    924       189  
Proceeds from property sales
    14        
Cost of removal, net of salvage
    (15 )     (28 )
Change in construction payables
    136       28  
Other investing activities
    13       7  
 
           
Net cash used for investing activities
    (884 )     (1,088 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (54 )     132  
Proceeds —
               
Long-term debt issuances
    937       350  
Common stock issuances
    193       147  
Redemptions —
               
Long-term debt
    (824 )     (256 )
Payment of common stock dividends
    (385 )     (359 )
Payment of dividends on preferred and preference stock of subsidiaries
    (16 )     (16 )
Other financing activities
    (2 )     1  
 
           
Net cash used for financing activities
    (151 )     (1 )
 
           
Net Change in Cash and Cash Equivalents
    (37 )     (351 )
Cash and Cash Equivalents at Beginning of Period
    447       690  
 
           
Cash and Cash Equivalents at End of Period
  $ 410     $ 339  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $17 and $21 capitalized for 2011 and 2010, respectively)
  $ 197     $ 182  
Income taxes (net of refunds)
    (357 )     6  
Noncash transactions — accrued property additions at end of period
    531       373  
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 March 31,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 410     $ 447  
Restricted cash and cash equivalents
    7       68  
Receivables —
               
Customer accounts receivable
    1,024       1,140  
Unbilled revenues
    341       420  
Under recovered regulatory clause revenues
    220       209  
Other accounts and notes receivable
    249       285  
Accumulated provision for uncollectible accounts
    (26 )     (25 )
Fossil fuel stock, at average cost
    1,350       1,308  
Materials and supplies, at average cost
    828       827  
Vacation pay
    150       151  
Prepaid expenses
    435       784  
Other regulatory assets, current
    199       210  
Other current assets
    53       59  
 
           
Total current assets
    5,240       5,883  
 
           
Property, Plant, and Equipment:
               
In service
    57,408       56,731  
Less accumulated depreciation
    20,384       20,174  
 
           
Plant in service, net of depreciation
    37,024       36,557  
Other utility plant, net
    67        
Nuclear fuel, at amortized cost
    738       670  
Construction work in progress
    4,872       4,775  
 
           
Total property, plant, and equipment
    42,701       42,002  
 
           
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    1,369       1,370  
Leveraged leases
    630       624  
Miscellaneous property and investments
    267       277  
 
           
Total other property and investments
    2,266       2,271  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    1,263       1,280  
Prepaid pension costs
    104       88  
Unamortized debt issuance expense
    178       178  
Unamortized loss on reacquired debt
    269       274  
Deferred under recovered regulatory clause revenues
    133       218  
Other regulatory assets, deferred
    2,432       2,402  
Other deferred charges and assets
    433       436  
 
           
Total deferred charges and other assets
    4,812       4,876  
 
           
Total Assets
  $ 55,019     $ 55,032  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Liabilities and Stockholders’ Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $ 1,435     $ 1,301  
Notes payable
    1,243       1,297  
Accounts payable
    1,315       1,275  
Customer deposits
    333       332  
Accrued taxes —
               
Accrued income taxes
    13       8  
Unrecognized tax benefits
    183       187  
Other accrued taxes
    192       440  
Accrued interest
    259       225  
Accrued vacation pay
    190       194  
Accrued compensation
    165       438  
Liabilities from risk management activities
    133       152  
Other regulatory liabilities, current
    83       88  
Other current liabilities
    493       535  
 
           
Total current liabilities
    6,037       6,472  
 
           
Long-term Debt
    18,133       18,154  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    7,673       7,554  
Deferred credits related to income taxes
    233       235  
Accumulated deferred investment tax credits
    525       509  
Employee benefit obligations
    1,575       1,580  
Asset retirement obligations
    1,283       1,257  
Other cost of removal obligations
    1,170       1,158  
Other regulatory liabilities, deferred
    335       312  
Other deferred credits and liabilities
    508       517  
 
           
Total deferred credits and other liabilities
    13,302       13,122  
 
           
Total Liabilities
    37,472       37,748  
 
           
Redeemable Preferred Stock of Subsidiaries
    375       375  
 
           
Stockholders’ Equity:
               
Common Stockholders’ Equity:
               
Common stock, par value $5 per share —
               
Authorized — 1.5 billion shares
               
Issued — March 31, 2011: 850 million shares
               
— December 31, 2010: 844 million shares
               
Treasury — March 31, 2011: 0.5 million shares
               
— December 31, 2010: 0.5 million shares
               
Par value
    4,248       4,219  
Paid-in capital
    3,894       3,702  
Treasury, at cost
    (15 )     (15 )
Retained earnings
    8,404       8,366  
Accumulated other comprehensive loss
    (66 )     (70 )
 
           
Total Common Stockholders’ Equity
    16,465       16,202  
Preferred and Preference Stock of Subsidiaries
    707       707  
 
           
Total Stockholders’ Equity
    17,172       16,909  
 
           
Total Liabilities and Stockholders’ Equity
  $ 55,019     $ 55,032  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Consolidated Net Income
  $ 438     $ 511  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Changes in fair value, net of tax of $2 and $1, respectively
    3       1  
Reclassification adjustment for amounts included in net income, net of tax of $2 and $3, respectively
    3       6  
Marketable securities:
               
Change in fair value, net of tax of $- and $1, respectively
    (1 )     2  
Pension and other post retirement benefit plans:
               
Reclassification adjustment for amounts included in net income, net of tax of $1 and $-, respectively
    (1 )      
 
           
Total other comprehensive income (loss)
    4       9  
 
           
Dividends on preferred and preference stock of subsidiaries
    (16 )     (16 )
 
           
Comprehensive Income
  $ 426     $ 504  
 
           
The accompanying notes as they relate to Southern Company are an integral part of these condensed financial statements.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
OVERVIEW
Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the traditional operating companies — Alabama Power, Georgia Power, Gulf Power, and Mississippi Power — and Southern Power. The traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets and sells electricity at market-based rates in the wholesale market. Southern Company’s other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESS — The Southern Company System — “Traditional Operating Companies,” “Southern Power,” and “Other Businesses” in Item 1 of the Form 10-K.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Southern Company in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(73)   (14.6)
 
Southern Company’s first quarter 2011 net income after dividends on preferred and preference stock of subsidiaries was $422 million ($0.50 per share) compared to $495 million ($0.60 per share) for the first quarter 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of decreases in revenues in the first quarter 2011 due to the significantly colder weather in the first quarter 2010, a decrease in wholesale revenues primarily at Alabama Power, a decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, and increases in operations and maintenance expenses. The decrease for the first quarter 2011 was partially offset by an increase in retail base revenues at Georgia Power pursuant to the 2010 ARP and by increases in revenues associated with new PPAs at Southern Power.
Retail Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(63)   (1.8)
 
In the first quarter 2011, retail revenues were $3.4 billion compared to $3.5 billion for the corresponding period in 2010.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues follow:
                 
    First Quarter
    2011
 
    (in millions)   (% change)
Retail — prior year
  $ 3,459          
Estimated change in —
               
Rates and pricing
    166       4.8  
Sales growth (decline)
    (5 )     (0.1 )
Weather
    (90 )     (2.6 )
Fuel and other cost recovery
    (134 )     (3.9 )
 
Retail – current year
  $ 3,396       (1.8 )%
 
Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to Georgia Power’s retail base rate increase and NCCR revenues. Also contributing to the increase were revenues associated with Alabama Power’s Rate CNP Environmental due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.
Revenues attributable to changes in sales decreased in the first quarter 2011 when compared to the corresponding period in 2010. The decrease was due to a 0.9% decrease in weather-adjusted residential KWH sales and a 0.8% decrease in weather-adjusted commercial KWH sales. In addition, weather-adjusted industrial KWH sales increased 6.4% due to increased production activity in the primary metals and chemical sectors.
Revenues resulting from changes in weather decreased $90 million in the first quarter 2011 as a result of significantly colder weather in the corresponding period in 2010.
Fuel and other cost recovery revenues decreased $134 million in the first quarter 2011 when compared to the corresponding period in 2010. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.
Wholesale Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(93)   (17.2)
 
Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market cost of available energy compared to the Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of the Southern Company system generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the variable cost to produce the energy.
In the first quarter 2011, wholesale revenues were $449 million compared to $542 million for the corresponding period in 2010, reflecting a $71 million decrease in energy revenues and a $22 million decrease in capacity revenues. The decrease in the first quarter 2011 was primarily due to a 24.2% decrease in KWH sales mainly due to the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in June, July, and December 2010 and January 2011.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Electric Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$15   11.1
 
In the first quarter 2011, other electric revenues were $150 million compared to $135 million for the corresponding period in 2010. The increase in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of an increase in transmission revenues.
Other Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(4)   (20.3)
 
In the first quarter 2011, other revenues were $17 million compared to $21 million for the corresponding period in 2010. The decrease in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $4 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
                 
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel*
  $ (169 )     (10.3 )
Purchased power
    (27 )     (20.8 )
         
Total fuel and purchased power expenses
  $ (196 )        
         
*   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 first quarter 2011 were $1.6 billion compared to $1.8 billion for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $63 million decrease related to total KWHs generated and purchased and a $133 million net decrease in the average cost of fuel and purchased power. The decrease in total KWHs generated and purchased resulted primarily from a decrease in customer demand, and the net decrease in the cost of fuel and purchased power resulted primarily from a 20.6% decrease in the average cost of gas per KWH generated and a 4.9% decrease in the average cost of coal per KWH generated.
Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not have a significant effect on net income. See FUTURE EARNINGS POTENTIAL — “State PSC Matters — Retail Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly affect net income.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Southern Company’s cost of generation and purchased power are as follows:
                         
    First Quarter   First Quarter   Percent
Average Cost   2011   2010   Change
    (cents per net KWH)        
 
Fuel
    3.25       3.60       (9.7 )
Purchased power
    9.25       7.37       25.5  
 
Energy purchases will vary depending on demand for energy within the Southern Company service area, the market cost of available energy as compared to the cost of Southern Company system-generated energy, and the availability of Southern Company system generation.
Other Operations and Maintenance Expenses
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$36   3.8
 
In the first quarter 2011, other operations and maintenance expenses were $944 million compared to $908 million for the corresponding period in 2010. The increase in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $30 million increase in scheduled outage and maintenance costs, a $10 million increase in commodity and labor costs, a $9 million increase in transmission and distribution expenses, and a $3 million increase in customer service related costs. The increase was partially offset by a $16 million decrease in administrative and general costs primarily due to decreases in property insurance, pension costs, and other employee benefits.
Depreciation and Amortization
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$75   21.9
 
In the first quarter 2011, depreciation and amortization was $418 million compared to $343 million for the corresponding period in 2010. The increase for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $50 million decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC and additional depreciation on plant in service related to environmental, transmission, and distribution projects. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information on the other cost of removal regulatory liability.
Taxes Other Than Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$8   3.9
 
In the first quarter 2011, taxes other than income taxes were $220 million compared to $212 million for the corresponding period in 2010. The increase for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of increases in property and payroll taxes.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(14)   (28.6)
 
In the first quarter 2011, AFUDC equity was $35 million compared to $49 million for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily due to the inclusion of Georgia Power’s Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011 which reduced the amount of AFUDC capitalized. Also contributing to the decrease was the completion of environmental construction projects at Alabama Power. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” herein for additional information.
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(5)   (1.8)
 
In the first quarter 2011, income taxes were $231 million compared to $236 million for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of lower pre-tax earnings, partially offset by a decrease in the first quarter 2010 in uncertain tax positions at Georgia Power related to state income tax credits that remain subject to litigation. See Notes (B) and (G) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of the facilities of Southern Company’s subsidiaries which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.
In April 2010, the EPA proposed an Industrial Boiler MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. Georgia Power has delayed the decision to convert Plant

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mitchell Unit 3 to biomass until there is greater clarity regarding these regulations. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time.
In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. In a decision published on April 6, 2011, the EPA responded to an environmental group’s request for reconsideration by attempting to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. Absent a stay, the EPA’s decision will become effective May 6, 2011 and the rule under which Alabama Power has been operating since January 2009 may not be available unless Alabama Power’s appeal is resolved in its favor by the court. If the EPA’s decision is allowed to take effect, it will likely impact unit availability and result in increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Southern Company affiliates’ existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of the facilities of Southern Company’s subsidiaries may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.
State PSC Matters
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In previous years, the traditional operating companies have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power of approximately $348 million at March 31, 2011. Mississippi Power collected all previously under recovered fuel costs and, as of March 31, 2011, had a total over recovered fuel balance of $58 million. At December 31, 2010, total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power were approximately $420 million and Mississippi Power had a total over recovered fuel balance of $55 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on Southern Company’s revenues or net income,

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
but does impact annual cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.
On March 1, 2011, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 0.61%. The decrease would reduce Georgia Power’s annual billings by approximately $43 million. The decrease in fuel costs is driven primarily by lower natural gas prices than those included in current rates. That decrease is a result of increases in natural gas supplies from the production of shale gas and lower industrial demand. If approved, the new rates will go into effect June 1, 2011. The ultimate outcome of this matter cannot be determined at this time.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
Alabama Power Retail Regulatory Matters
Natural Disaster Reserve
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Natural Disaster Reserve” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Alabama Power — Natural Disaster Reserve” in Item 8 of the Form 10-K.
On April 27, 2011, devastating storms swept through the central part of Alabama causing significant damage in parts of the service territory of Alabama Power. Over 400,000 of Alabama Power’s 1.4 million customers were without electrical service immediately after the storms, resulting from significant damage to Alabama Power’s transmission and distribution facilities. The preliminary estimated cost associated with repairing the damage to facilities and restoring electrical service to customers is between $40 million and $55 million for operations and maintenance expenses and between $180 million and $225 million for capital expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.
At March 31, 2011, the NDR had an accumulated balance of $127 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.
Georgia Power Retail Regulatory Matters
Plant Branch Units 1 and 2 De-certification
See “Environmental Matters — Air Quality” and “— Water Quality” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “— Water Quality,” and “— Coal Combustion Byproducts” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its coal-fired generating units in light of these regulations; and the 2010 ARP.

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On March 22, 2011, the board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule. The proposed modifications would change the compliance dates for certain of Georgia Power’s coal-fired generating units as follows:
         
 
  Scherer 3   July 1, 2011
 
  Branch 1   December 31, 2013
 
  Branch 2   October 1, 2013
 
  Branch 3   October 1, 2015
 
  Branch 4   December 31, 2015
The Multi-Pollutant Rule is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. The Utility MACT rule will also regulate emissions of mercury, in addition to other air pollutants. All required controls, including SCR, scrubber, and baghouse, are expected to be operational at Plant Scherer Unit 3 by the required compliance date. As a result of these proposed rules, Georgia Power’s management expects to request that the Georgia PSC approve de-certification of its Plant Branch Units 1 and 2, totaling 569 MWs of capacity, as of the effective dates for controls under the Multi-Pollutant Rule as revised. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired units, including Plant Branch Units 3 and 4, in light of the proposed air quality rules, as well as additional potential federal regulations related to water quality and coal combustion byproducts. Georgia Power may determine that retiring and replacing certain of its existing units with new generating resources or purchased power is more economically efficient than installing the required controls.
Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated integrated resource plan will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Georgia Power currently expects to file an update to its integrated resource plan in late summer 2011, which would include the Plant Branch Units 1 and 2 de-certification request. In connection with this filing, Georgia Power expects to request the Georgia PSC to approve the deferral and related amortization of the retail portion of the related costs associated with the de-certification request. Georgia Power moved the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net of depreciation. Consistent with current ratemaking treatment, Georgia Power will continue to depreciate these units using the composite straight-line rates approved by the Georgia PSC, and upon actual retirement, expects to include the units’ remaining net carrying value in rate base. However, the recovery periods for these units may change in connection with Georgia Power’s updated integrated resource plan. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s financial statements.
The ultimate outcome of these matters cannot be determined at this time.
Storm Damage Reserve
During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power maintains a reserve for property damage to cover the operating and maintenance cost of damages from major storms to its transmission and distribution lines as mandated by the Georgia PSC. As a result of this regulatory treatment, the storms are not expected to have a material impact on Southern Company’s financial statements. See Note 1 to the financial statements of Southern Company under “Storm Damage Reserves” in Item 8 of the Form 10-K for additional information.
Income Tax Matters
Bonus Depreciation
In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Company. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Southern Company estimates the potential increased cash flow for 2011 to be between approximately $350 million and $450 million. The ultimate outcome of this matter cannot be determined at this time.

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Construction Program
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including natural gas, biomass, and potentially solar units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC facility at Mississippi Power, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements of Southern Company under “Construction Program” in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction,” “Retail Regulatory Matters — Georgia Power — Other Construction,” and “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” and “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein for additional information.
On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. According to published reports, the owner of these units is continuing work to stabilize these units following a loss of operation of the cooling systems for the units. While the Southern Company system will continue to monitor this developing situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of the existing nuclear generating units of Alabama Power and Georgia Power.
The events in Japan have created uncertainties that may affect transportation, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements.
See RISK FACTORS in Item 1A of Southern Company in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Company’s financial condition remained stable at March 31, 2011. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $998 million for the first quarter 2011, an increase of $260 million from the corresponding period in 2010. Significant changes in operating cash flow for the first quarter 2011 as compared to the corresponding period in 2010 include a decrease in accounts receivable balances primarily due to greater recovery of fuel costs. Net cash used for investing activities totaled $884 million for the first quarter 2011, a decrease of $204 million from the corresponding period in 2010. This decrease was primarily due to an increase in construction-related accounts payable. Net cash used for financing activities totaled $151 million for the first quarter 2011, an increase of $150 million from the corresponding period in 2010. This increase was primarily due to a decrease in notes payable.
Significant balance sheet changes for the first quarter 2011 include a decrease in prepaid expenses of $349 million due to a reduction in prepaid income taxes and an increase of $699 million 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 $263 million.
The market price of Southern Company’s common stock at March 31, 2011 was $38.11 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $19.39 per share, representing a market-to-book ratio of 196.5%, compared to $38.23, $19.21, and 199.0%, respectively, at the end of 2010. The dividend for the first quarter 2011 was $0.4550 per share compared to $0.4375 per share in the first quarter 2010. In April 2011, the quarterly dividend payable in June 2011 was increased to $0.4725 per share.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for the construction programs of its subsidiaries and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and interest, and derivative obligations. Approximately $1.4 billion will be required through March 31, 2012 for maturities and announced repurchases of long-term debt.
The construction programs of Southern Company’s subsidiaries are currently estimated to include a base level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, Southern Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Southern Company estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2011, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.
Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined Construction and Operating License for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.
In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power.
Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At March 31, 2011, Southern Company and its subsidiaries had approximately $410 million of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks, of which $1.6 billion expire in 2011 and $3.3 billion expire in 2012. Of the credit arrangements expiring in 2011 and 2012, $81 million contain provisions allowing two-year term loans executable at expiration and $952 million contain provisions allowing one-year term loans executable at expiration. At March 31, 2011, approximately $1.4 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies. At March 31, 2011, the Southern Company system had approximately $1.2 billion of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, Southern Company had an average of $1.2 billion of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1.6 billion. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Off-Balance Sheet Financing Arrangements
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power is required 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 March 31, 2011, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $495 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. Southern Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, Southern Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Company’s policies in areas such as counterparty exposure and risk management practices. Southern Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:
         
    First Quarter
    2011
    Changes
    Fair Value
    (in millions)
 
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (196 )
Contracts realized or settled
    38  
Current period changes(a)
     
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (158 )
 
 
(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 ended March 31, 2011 was an increase of $38 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Southern Company had a net hedge volume of 154.2 million mmBtu with a weighted average contract cost approximately $1.09 per mmBtu above market prices, compared to 149.3 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.35 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.
The fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:
                 
Asset (Liability) Derivatives   March 31, 2011   December 31, 2010
    (in millions)
Regulatory hedges
  $ (156 )   $ (193 )
Cash flow hedges
          (1 )
Not designated
    (2 )     (2 )
 
Total fair value
  $ (158 )   $ (196 )
 
Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Total net unrealized pre-tax gains (losses) recognized in income for the three months ended March 31, 2011 and 2010 were not material.
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:
                                 
    March 31, 2011
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (158 )     (125 )     (33 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (158 )   $ (125 )   $ (33 )   $  
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Southern Company in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
During the first quarter 2011, Southern Company issued approximately 5.8 million shares of common stock for $193 million through the Southern Investment Plan and employee and director stock plans. The proceeds were primarily used for general corporate purposes, including the investment by Southern Company in its subsidiaries, and to repay short-term indebtedness.
In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.
In January 2011, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used for general corporate purposes, including Georgia Power’s continuous construction program.
In March 2011, Alabama Power issued $250 million aggregate principal amount of Series 2011A 5.50% Senior Notes due March 15, 2041. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program.
In March 2011, Georgia Power’s $300 million variable rate bank term loan due on March 4, 2011 matured and was partially replaced by two one-year $125 million aggregate principal amount variable rate bank loans that bear interest based on one-month LIBOR.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to March 31, 2011, Georgia Power issued $250 million aggregate principal amount of Series 2011B 3.0% Senior Notes due April 15, 2016. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.
Also subsequent to March 31, 2011, Georgia Power purchased and is holding $113.5 million of pollution control revenue bonds. The bonds are expected to be re-marketed to investors at a future date.
Subsequent to March 31, 2011, Gulf Power extended the maturity date of a $110 million bank note until June 30, 2011.
Subsequent to March 31, 2011, Mississippi Power entered into a one-year $75 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay short-term debt and for general corporate purposes, including Mississippi Power’s continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative And Qualitative Disclosures About Market Risk.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for each registrant and Note 1 to the financial statements of each registrant under “Financial Instruments,” Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
     (a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this quarterly report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
     (b) Changes in internal controls.
There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the first quarter 2011 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

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ALABAMA POWER COMPANY

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ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                 
     For the Three Months  
     Ended March 31,  
    2011     2010  
    (in millions)  
Operating Revenues:
               
Retail revenues
  $ 1,126     $ 1,176  
Wholesale revenues, non-affiliates
    68       172  
Wholesale revenues, affiliates
    75       98  
Other revenues
    51       49  
 
           
Total operating revenues
    1,320       1,495  
 
           
Operating Expenses:
               
Fuel
    395       489  
Purchased power, non-affiliates
    11       18  
Purchased power, affiliates
    46       52  
Other operations and maintenance
    297       310  
Depreciation and amortization
    157       145  
Taxes other than income taxes
    85       82  
 
           
Total operating expenses
    991       1,096  
 
           
Operating Income
    329       399  
Other Income and (Expense):
               
Allowance for equity funds used during construction
    5       13  
Interest income
    4       4  
Interest expense, net of amounts capitalized
    (74 )     (75 )
Other income (expense), net
    (6 )     (6 )
 
           
Total other income and (expense)
    (71 )     (64 )
 
           
Earnings Before Income Taxes
    258       335  
Income taxes
    96       122  
 
           
Net Income
    162       213  
Dividends on Preferred and Preference Stock
    10       10  
 
           
Net Income After Dividends on Preferred and Preference Stock
  $ 152     $ 203  
 
           
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Net Income After Dividends on Preferred and Preference Stock
  $ 152     $ 203  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Changes in fair value, net of tax of $2 and $-, respectively
    2        
Reclassification adjustment for amounts included in net income, net of tax of $- and $1, respectively
          1  
 
           
Total other comprehensive income (loss)
    2       1  
 
           
Comprehensive Income
  $ 154     $ 204  
 
           
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 Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Net income
  $ 162     $ 213  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    185       168  
Deferred income taxes
    59       47  
Allowance for equity funds used during construction
    (5 )     (13 )
Pension, postretirement, and other employee benefits
    (11 )     (8 )
Stock based compensation expense
    3       3  
Hedge settlements
    4        
Storm damage accruals
    1       2  
Other, net
    (4 )     4  
Changes in certain current assets and liabilities —
               
-Receivables
    51       11  
-Fossil fuel stock
    3       13  
-Materials and supplies
    10       (3 )
-Other current assets
    (69 )     (78 )
-Accounts payable
    (153 )     (75 )
-Accrued taxes
    160       69  
-Accrued compensation
    (67 )     (41 )
-Other current liabilities
    (2 )     (38 )
 
           
Net cash provided from operating activities
    327       274  
 
           
Investing Activities:
               
Property additions
    (213 )     (255 )
Distribution of restricted cash from pollution control revenue bonds
    11       5  
Nuclear decommissioning trust fund purchases
    (97 )     (39 )
Nuclear decommissioning trust fund sales
    97       39  
Cost of removal, net of salvage
    (8 )     (5 )
Change in construction payables
    (2 )     (26 )
Other investing activities
    (12 )     (17 )
 
           
Net cash used for investing activities
    (224 )     (298 )
 
           
Financing Activities:
               
Proceeds —
               
Capital contributions from parent company
    5       6  
Senior notes issuances
    250        
Redemptions —
               
Senior notes
    (200 )      
Payment of preferred and preference stock dividends
    (10 )     (10 )
Payment of common stock dividends
    (138 )     (136 )
Other financing activities
    (5 )     (1 )
 
           
Net cash used for financing activities
    (98 )     (141 )
 
           
Net Change in Cash and Cash Equivalents
    5       (165 )
Cash and Cash Equivalents at Beginning of Period
    154       368  
 
           
Cash and Cash Equivalents at End of Period
  $ 159     $ 203  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $2 and $5 capitalized for 2011 and 2010, respectively)
  $ 72     $ 59  
Income taxes (net of refunds)
    (110 )     19  
Noncash transactions — accrued property additions at end of period
    26       48  
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 March 31,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 159     $ 154  
Restricted cash and cash equivalents
    7       18  
Receivables —
               
Customer accounts receivable
    321       362  
Unbilled revenues
    110       153  
Under recovered regulatory clause revenues
    10       5  
Other accounts and notes receivable
    33       35  
Affiliated companies
    89       57  
Accumulated provision for uncollectible accounts
    (10 )     (10 )
Fossil fuel stock, at average cost
    388       391  
Materials and supplies, at average cost
    336       346  
Vacation pay
    56       55  
Prepaid expenses
    140       208  
Other regulatory assets, current
    32       38  
Other current assets
    7       10  
 
           
Total current assets
    1,678       1,822  
 
           
Property, Plant, and Equipment:
               
In service
    20,218       19,966  
Less accumulated provision for depreciation
    7,038       6,931  
 
           
Plant in service, net of depreciation
    13,180       13,035  
Nuclear fuel, at amortized cost
    317       283  
Construction work in progress
    428       547  
 
           
Total property, plant, and equipment
    13,925       13,865  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    63       64  
Nuclear decommissioning trusts, at fair value
    578       552  
Miscellaneous property and investments
    71       71  
 
           
Total other property and investments
    712       687  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    456       488  
Prepaid pension costs
    267       257  
Deferred under recovered regulatory clause revenues
    5       4  
Other regulatory assets, deferred
    673       675  
Other deferred charges and assets
    209       196  
 
           
Total deferred charges and other assets
    1,610       1,620  
 
           
Total Assets
  $ 17,925     $ 17,994  
 
           
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $     $ 200  
Accounts payable —
               
Affiliated
    158       210  
Other
    170       273  
Customer deposits
    86       86  
Accrued taxes —
               
Accrued income taxes
    4       2  
Other accrued taxes
    51       32  
Accrued interest
    62       63  
Accrued vacation pay
    45       45  
Accrued compensation
    34       99  
Liabilities from risk management activities
    24       31  
Over recovered regulatory clause revenues
    23       22  
Other current liabilities
    39       41  
 
           
Total current liabilities
    696       1,104  
 
           
Long-term Debt
    6,235       5,987  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,774       2,747  
Deferred credits related to income taxes
    86       85  
Accumulated deferred investment tax credits
    155       157  
Employee benefit obligations
    309       311  
Asset retirement obligations
    528       520  
Other cost of removal obligations
    712       701  
Other regulatory liabilities, deferred
    236       217  
Other deferred credits and liabilities
    90       87  
 
           
Total deferred credits and other liabilities
    4,890       4,825  
 
           
Total Liabilities
    11,821       11,916  
 
           
Redeemable Preferred Stock
    342       342  
 
           
Preference Stock
    343       343  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $40 per share —
               
Authorized - 40,000,000 shares
               
Outstanding - 30,537,500 shares
    1,222       1,222  
Paid-in capital
    2,166       2,156  
Retained earnings
    2,036       2,022  
Accumulated other comprehensive loss
    (5 )     (7 )
 
           
Total common stockholder’s equity
    5,419       5,393  
 
           
Total Liabilities and Stockholder’s Equity
  $ 17,925     $ 17,994  
 
           
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(51)   (25.1)
   
Alabama Power’s net income after dividends on preferred and preference stock for the first quarter 2011 was $152 million compared to $203 million for the corresponding period in 2010. The decrease was primarily due to reductions in wholesale revenues from sales to non-affiliates in the first quarter 2011 and significantly colder weather in the first quarter 2010. The decrease in revenue was partially offset by decreases in operations and maintenance expenses and an increase in revenues under Rate CNP Environmental associated with the completion of construction projects related to environmental mandates.
Retail Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(50)   (4.3)
   
In the first quarter 2011, retail revenues were $1.13 billion compared to $1.18 billion for the corresponding period in 2010.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues are as follows:
                 
    First Quarter
    2011
    (in millions)   (% change)
 
Retail – prior year
  $ 1,176          
Estimated change in —
               
Rates and pricing
    26       2.2  
Sales growth (decline)
    (3 )     (0.2 )
Weather
    (45 )     (3.9 )
Fuel and other cost recovery
    (28 )     (2.4 )
 
Retail – current year
  $ 1,126       (4.3 )%
     
Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to increased revenues associated with Rate CNP Environmental. The increase was due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.
Revenues attributable to changes in sales decreased slightly in the first quarter 2011 from the corresponding period in 2010. Weather-adjusted residential KWH energy sales decreased 2.7% due to a decrease in customer demand. Weather-adjusted commercial KWH energy sales decreased 1.0% due to decreases in the number of customers and demand. Industrial KWH energy sales increased 9.5% due to an increase in demand resulting from changes in production levels primarily in the chemical and primary metals sectors.
Revenues resulting from changes in weather decreased in the first quarter 2011 when compared to the corresponding period in 2010. Residential and commercial sales revenues decreased 7.1% and 1.5%, respectively, as a result of significantly colder weather in the corresponding period in 2010.
Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to a decrease in fuel costs associated with decreased KWH generation and a decrease in costs associated with PPAs certificated by the Alabama PSC. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(104)   (60.5)
   
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 first quarter 2011, wholesale revenues from non-affiliates were $68 million compared to $172 million for the corresponding period in 2010, reflecting a $55 million decrease in revenue from energy sales and a $49 million decrease in capacity revenue. This decrease was primarily due to a 66.3% decrease in KWH sales, partially offset by a

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
16.8% increase in the price. In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $102 million revenue reduction as compared to the first quarter 2010. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(23)   (23.5)
   
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 first quarter 2011, wholesale revenues from affiliates were $75 million compared to $98 million for the corresponding period in 2010. This decrease was due to a 19.0% decrease in price and a 5.3% decrease in KWH sales.
Fuel and Purchased Power Expenses
                 
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel*
  $ (94 )     (19.2 )
Purchased power – non-affiliates
    (7 )     (38.9 )
Purchased power – affiliates
    (6 )     (11.5 )
       
Total fuel and purchased power expenses
  $ (107 )        
       
*   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 first quarter 2011, total fuel and purchased power expenses were $452 million compared to $559 million for the corresponding period in 2010. This decrease was primarily due to a $49 million decrease in total KWHs generated, a $28 million decrease in the cost of fuel, and a $20 million decrease in the average cost of purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Rate ECR. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.
Details of Alabama Power’s cost of generation and purchased power are as follows:
                         
    First Quarter   First Quarter   Percent
Average Cost   2011   2010   Change
    (cents per net KWH)        
Fuel*
    2.62       2.80       (6.4 )
Purchased power
    5.26       7.08       (25.7 )
 
*   KWHs generated by hydro are excluded from the average cost of fuel.
In the first quarter 2011, fuel expense was $395 million compared to $489 million for the corresponding period in 2010. The $94 million decrease was due to a 14.6% decrease in KWHs generated by coal, an 8.0% decrease in KWHs generated by natural gas, and a 17.8% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-Affiliates
In the first quarter 2011, purchased power expense from non-affiliates was $11 million compared to $18 million for the corresponding period in 2010. This decrease was related to a 75.6% decrease in the amount of energy purchased, partially offset by a 140.3% 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 first quarter 2011, purchased power expense from affiliates was $46 million compared to $52 million for the corresponding period in 2010. This decrease was related to a 39.9% decrease in the average cost per KWH, partially offset by a 14.0% increase in the amount of energy purchased.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(13)   (4.2)
   
In the first quarter 2011, other operations and maintenance expenses were $297 million compared to $310 million for the corresponding period in 2010. Administration and general expenses decreased $9 million related to decreases in affiliated service companies’ expenses, property insurance expense, employee medical and other benefit-related expenses, and injuries and damages expenses. Nuclear production expenses decreased $8 million primarily due to a change to the nuclear maintenance outage accounting process associated with the routine refueling activities, as approved by the Alabama PSC in August 2010. As a result, no nuclear maintenance outage expenses will be recognized in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Nuclear Outage Accounting Order” of Alabama Power in Item 7 of the Form 10-K for additional information. In addition, the decrease in nuclear production expenses was partially offset by an increase in maintenance costs related to increases in labor. Transmission and distribution expenses increased $4 million primarily due to overhead line clearing costs.
Depreciation and Amortization
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$12   8.3
   
In the first quarter 2011, depreciation and amortization was $157 million compared to $145 million for the corresponding period in 2010. The increase was due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Allowance for Equity Funds Used During Construction
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(8)   (61.5)
   
In the first quarter 2011, AFUDC equity was $5 million compared to $13 million for the corresponding period in 2010. This decrease was due to the completion of environmental construction projects at Plants Barry, Gaston, and Miller.
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(26)   (21.3)
   
For the first quarter 2011, income taxes were $96 million compared to $122 million for the corresponding period in 2010. This decrease was primarily due to lower pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power’s future earnings potential. The level of Alabama Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include Alabama Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Changes in economic conditions impact sales for Alabama Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Alabama Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.
In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. In a decision published on April 6, 2011, the EPA responded to an environmental group’s request for reconsideration by attempting to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. Absent a stay, the EPA’s decision will become effective May 6, 2011 and the rule under which Alabama Power has been operating since January 2009 may not be available unless Alabama Power’s appeal is resolved in its favor by the court. If the EPA’s decision is allowed to take effect, it will likely impact unit availability and result in increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Alabama Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Alabama Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.
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 under recovered fuel costs as of March 31, 2011 totaled $15 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at March 31, 2011 are included in under recovered regulatory clause revenues and deferred under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered fuel costs.
Natural Disaster Reserve
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information.
On April 27, 2011, devastating storms swept through the central part of Alabama causing significant damage in parts of the service territory of Alabama Power. Over 400,000 of Alabama Power’s 1.4 million customers were without electrical service immediately after the storms, resulting from significant damage to Alabama Power’s transmission and distribution facilities. The preliminary estimated cost associated with repairing the damage to facilities and restoring electrical service to customers is between $40 million and $55 million for operations and maintenance expenses and between $180 million and $225 million for capital expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At March 31, 2011, the NDR had an accumulated balance of $127 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.
Income Tax Matters
Bonus Depreciation
In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Alabama Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Alabama Power estimates the potential increased cash flow for 2011 to be between approximately $100 million and $150 million. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and 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 events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of existing nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. The ultimate outcome of these events cannot be determined at this time. See RISK FACTORS of Alabama Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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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 GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Alabama Power’s financial condition remained stable at March 31, 2011. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $327 million for the first three months of 2011, an increase of $53 million as compared to the first three months of 2010. The increase in cash provided from operating activities was primarily due to accrued taxes related to refunds received from bonus depreciation and receivables. This is partially offset by a decrease in accounts payable associated with payables to affiliates, a decrease in net income, and the under collection of regulatory clause revenues. Net cash used for investing activities totaled $224 million for the first three months of 2011 primarily due to gross property additions related to steam generation equipment, nuclear fuel, and transmission and distribution expenditures. Net cash used for financing activities totaled $98 million for the first three months of 2011 primarily due to payment of common stock dividends and the issuance and maturity of senior notes. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first three months of 2011 include decreases of $103 million in other accounts payable related to the timing of outstanding checks associated with property tax payments, $68 million in prepaid expenses related to income taxes, $43 million in unbilled revenues, and $41 million in customer accounts receivable; and increases of $60 million in property, plant, and equipment associated with nuclear fuel and routine property additions and $48 million in debt resulting from greater issuances than maturities.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. There are no requirements through March 31, 2012 for maturities of long-term debt.
The approved construction program of Alabama Power includes a base level investment of $0.9 billion for 2011, $0.9 billion for 2012, and $1.1 billion for 2013. Included in Alabama Power’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. Alabama Power currently anticipates that additional expenditures may be required to comply with anticipated statutes and regulations. Such additional expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013,

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
respectively. If the EPA’s proposed Utility MACT rule is finalized as proposed, Alabama Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be close to the upper end of the estimates set forth above. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power’s current liabilities sometimes exceed current assets because of Alabama Power’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Alabama Power had at March 31, 2011 cash and cash equivalents of approximately $159 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $506 million expire in 2011 and $765 million expire in 2012. Of the credit arrangements that expire in 2011, $372 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 $798 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. At March 31, 2011, Alabama Power had no commercial paper borrowings outstanding. During the first quarter 2011, Alabama Power had an average of $88 million of commercial paper outstanding at a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $255 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $303 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.

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ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
During the first quarter 2011, Alabama Power had interest rate swaps totaling $200 million expire, which did not materially increase market risk exposure relative to interest rate changes. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. 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 first quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:
         
    First Quarter
    2011
    Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (38 )
Contracts realized or settled
    11  
Current period changes(a)
     
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (27 )
 
(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 ended March 31, 2011 was an increase of $11 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Alabama Power had a net hedge volume of 31.1 million mmBtu with a weighted average contract cost approximately $0.90 per mmBtu above market prices, compared to 33.9 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.14 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 months ended March 31, 2011 and 2010 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
Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:
                                 
    March 31, 2011
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (27 )     (23 )     (4 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (27 )   $ (23 )   $ (4 )   $  
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Alabama Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In February 2011, Alabama Power’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured.
In March 2011, Alabama Power issued $250 million aggregate principal amount of Series 2011A 5.50% Senior Notes due March 15, 2041. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program. Alabama Power settled $200 million of interest rate hedges related to the Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.
In 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  
    Ended March 31,  
    2011     2010  
    (in millions)  
Operating Revenues:
               
Retail revenues
  $ 1,815     $ 1,792  
Wholesale revenues, non-affiliates
    83       110  
Wholesale revenues, affiliates
    11       14  
Other revenues
    80       68  
 
           
Total operating revenues
    1,989       1,984  
 
           
Operating Expenses:
               
Fuel
    677       758  
Purchased power, non-affiliates
    74       82  
Purchased power, affiliates
    163       162  
Other operations and maintenance
    422       389  
Depreciation and amortization
    173       114  
Taxes other than income taxes
    87       80  
 
           
Total operating expenses
    1,596       1,585  
 
           
Operating Income
    393       399  
Other Income and (Expense):
               
Allowance for equity funds used during construction
    25       35  
Interest expense, net of amounts capitalized
    (96 )     (93 )
Other income (expense), net
    (1 )     (6 )
 
           
Total other income and (expense)
    (72 )     (64 )
 
           
Earnings Before Income Taxes
    321       335  
Income taxes
    111       93  
 
           
Net Income
    210       242  
Dividends on Preferred and Preference Stock
    4       4  
 
           
Net Income After Dividends on Preferred and Preference Stock
  $ 206     $ 238  
 
           
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Net Income After Dividends on Preferred and Preference Stock
  $ 206     $ 238  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Reclassification adjustment for amounts included in net income, net of tax of $— and $2, respectively
    1       3  
 
           
Comprehensive Income
  $ 207     $ 241  
 
           
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 Three Months  
    Ended March 31,  
    2011     2010  
    (in millions)  
Operating Activities:
               
Net income
  $ 210     $ 242  
Adjustments to reconcile net income to net cash provided from operating activities –
               
Depreciation and amortization, total
    210       154  
Deferred income taxes
    56       59  
Deferred revenues
    2       (18 )
Deferred expenses
    33       25  
Allowance for equity funds used during construction
    (25 )     (35 )
Pension, postretirement, and other employee benefits
    (7 )     (4 )
Stock based compensation expense
    4       3  
Storm damage accruals
    5       5  
Other, net
    (52 )     (26 )
Changes in certain current assets and liabilities —
               
-Receivables
    122       (9 )
-Fossil fuel stock
    (30 )     81  
-Materials and supplies
    (9 )     1  
-Prepaid income taxes
    80       23  
-Other current assets
    (4 )     (8 )
-Accounts payable
    (50 )     (17 )
-Accrued taxes
    (194 )     (185 )
-Accrued compensation
    (65 )     (7 )
-Other current liabilities
    64       43  
 
           
Net cash provided from operating activities
    350       327  
 
           
Investing Activities:
               
Property additions
    (513 )     (625 )
Nuclear decommissioning trust fund purchases
    (830 )     (199 )
Nuclear decommissioning trust fund sales
    827       150  
Cost of removal, net of salvage
    1       (14 )
Change in construction payables, net of joint owner portion
    93       41  
Other investing activities
    (6 )     51  
 
           
Net cash used for investing activities
    (428 )     (596 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (62 )     (81 )
Proceeds —
               
Capital contributions from parent company
    171       460  
Pollution control revenue bonds issuances
    137        
Senior notes issuances
    300       350  
Other long-term debt issuances
    250        
Redemptions —
               
Pollution control revenue bonds
    (84 )      
Senior notes
    (101 )     (250 )
Other long-term debt
    (300 )      
Payment of preferred and preference stock dividends
    (4 )     (4 )
Payment of common stock dividends
    (224 )     (205 )
Other financing activities
    (2 )     (2 )
 
           
Net cash provided from financing activities
    81       268  
 
           
Net Change in Cash and Cash Equivalents
    3       (1 )
Cash and Cash Equivalents at Beginning of Period
    8       14  
 
           
Cash and Cash Equivalents at End of Period
  $ 11     $ 13  
 
           
Cash paid during the period for —
               
Interest (net of $9 and $13 capitalized for 2011 and 2010, respectively)
    $65     $ 62  
Income taxes (net of refunds)
    (77 )     (6 )
Noncash transactions — accrued property additions at end of period
    350       275  
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 March 31,     At December 31,  
Assets   2011     2010  
    (in millions)  
Current Assets:
               
Cash and cash equivalents
  $ 11     $ 8  
Receivables —
               
Customer accounts receivable
    540       580  
Unbilled revenues
    160       172  
Under recovered regulatory clause revenues
    188       184  
Joint owner accounts receivable
    54       60  
Other accounts and notes receivable
    52       67  
Affiliated companies
    21       21  
Accumulated provision for uncollectible accounts
    (13 )     (11 )
Fossil fuel stock, at average cost
    654       624  
Materials and supplies, at average cost
    380       371  
Vacation pay
    77       78  
Prepaid income taxes
    6       99  
Other regulatory assets, current
    107       105  
Other current assets
    66       80  
 
           
Total current assets
    2,303       2,438  
 
           
Property, Plant, and Equipment:
               
In service
    26,681       26,397  
Less accumulated provision for depreciation
    10,008       9,966  
 
           
Plant in service, net of depreciation
    16,673       16,431  
Other utility plant, net
    67        
Nuclear fuel, at amortized cost
    421       386  
Construction work in progress
    3,304       3,287  
 
           
Total property, plant, and equipment
    20,465       20,104  
 
           
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    69       70  
Nuclear decommissioning trusts, at fair value
    791       818  
Miscellaneous property and investments
    40       42  
 
           
Total other property and investments
    900       930  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    731       723  
Prepaid pension costs
    101       91  
Deferred under recovered regulatory clause revenues
    128       214  
Other regulatory assets, deferred
    1,224       1,207  
Other deferred charges and assets
    191       207  
 
           
Total deferred charges and other assets
    2,375       2,442  
 
           
Total Assets
  $ 26,043     $ 25,914  
 
           
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in millions)  
Current Liabilities:
               
Securities due within one year
  $ 379     $ 415  
Notes payable
    514       576  
Accounts payable —
               
Affiliated
    200       243  
Other
    644       574  
Customer deposits
    198       198  
Accrued taxes —
               
Accrued income taxes
    34       1  
Unrecognized tax benefits
    180       187  
Other accrued taxes
    95       328  
Accrued interest
    142       94  
Accrued vacation pay
    56       58  
Accrued compensation
    46       109  
Liabilities from risk management activities
    70       77  
Other cost of removal obligations, current
    31       31  
Nuclear decommissioning trust securities lending collateral
    100       144  
Other current liabilities
    162       134  
 
           
Total current liabilities
    2,851       3,169  
 
           
Long-term Debt
    8,169       7,931  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    3,773       3,718  
Deferred credits related to income taxes
    127       129  
Accumulated deferred investment tax credits
    227       229  
Employee benefit obligations
    685       684  
Asset retirement obligations
    721       705  
Other cost of removal obligations
    128       131  
Other deferred credits and liabilities
    196       211  
 
           
Total deferred credits and other liabilities
    5,857       5,807  
 
           
Total Liabilities
    16,877       16,907  
 
           
Preferred Stock
    45       45  
 
           
Preference Stock
    221       221  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - 9,261,500 shares
    398       398  
Paid-in capital
    5,467       5,291  
Retained earnings
    3,045       3,063  
Accumulated other comprehensive loss
    (10 )     (11 )
 
           
Total common stockholder’s equity
    8,900       8,741  
 
           
Total Liabilities and Stockholder’s Equity
  $ 26,043     $ 25,914  
 
           
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
In December 2010, the Georgia PSC approved the 2010 ARP including a base rate increase of approximately $562 million effective January 1, 2011. On March 1, 2011, Georgia Power filed a request with the Georgia PSC to adjust its fuel cost recovery rates. The Georgia PSC will conduct public hearings on the fuel cost recovery filing in early May 2011, with a final decision expected on May 24, 2011. If approved, the new fuel cost recovery rates will go into effect June 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
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(32)
  (13.4)
 
Georgia Power’s net income after dividends on preferred and preference stock for the first quarter 2011 was $206 million compared to $238 million for the corresponding period in 2010. The decrease was primarily due to a decrease in the amortization of the regulatory liability related to other cost of removal obligations, an increase in operating and maintenance expenses, a decrease in revenue due to significantly colder weather in the first quarter 2010, and higher income taxes. This decrease was partially offset by an increase in retail base revenues effective January 1, 2011 as authorized by the Georgia PSC in the 2010 ARP.
Retail Revenues
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$23   1.3
 
Retail revenues for the first quarters 2011 and 2010 were $1.8 billion.

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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:
                 
    First Quarter
    2011
    (in millions)   (% change)
Retail — prior year
  $ 1,792          
Estimated change in —
               
Rates and pricing
    141       7.9  
Sales growth (decline)
    (7 )     (0.4 )
Weather
    (31 )     (1.8 )
Fuel cost recovery
    (80 )     (4.4 )
 
Retail — current year
  $ 1,815       1.3 %
 
Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 due to the retail base rate increase and NCCR revenues.
Revenues attributable to changes in sales decreased in the first quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted residential KWH sales decreased 0.2%, weather-adjusted commercial KWH sales decreased 1.8%, and weather-adjusted industrial KWH sales increased 3.5% in the first quarter 2011 when compared to the corresponding period in 2010.
Revenues resulting from changes in weather decreased in the first quarter 2011 when compared to the corresponding period in 2010 as a result of significantly colder weather in the first quarter 2010.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $80 million in the first quarter of 2011 when compared to the corresponding period in 2010 due to decreased KWH sales and lower fuel costs.
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
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(27)
  (24.5)
 
Wholesale revenues from non-affiliates will vary depending on fuel prices, 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 first quarter 2011, wholesale revenues from non-affiliates were $83 million compared to $110 million in the corresponding period in 2010, reflecting a $21 million decrease in energy revenues and a $6 million decrease in capacity revenues. The decrease in the first quarter 2011 was primarily due to a 27.4% decrease in KWH sales from lower demand resulting from significantly colder weather in the first quarter 2010 and the expiration of the long-term unit power sales contract in May 2010.

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Other Revenues
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$12   17.6
 
In the first quarter 2011, other revenues were $80 million compared to $68 million in the corresponding period in 2010. This increase was primarily due to an $11 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies.
Fuel and Purchased Power Expenses
                 
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel*
  $ (81 )     (10.7 )
Purchased power — non-affiliates
    (8 )     (9.8 )
Purchased power — affiliates
    1       0.6  
         
Total fuel and purchased power expenses
  $ (88 )        
         
*   Fuel includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.
In the first quarter 2011, total fuel and purchased power expenses were $914 million compared to $1.0 billion in the corresponding period in 2010. The decrease was primarily due to a $34 million net decrease related to lower KWHs generated and purchased primarily due to lower customer demand as a result of significantly colder weather in 2010 and a $54 million decrease in the average cost of fuel and average price of purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – Fuel Cost Recovery” herein for additional information.
Details of Georgia Power’s cost of generation and purchased power are as follows:
                         
    First Quarter   First Quarter   Percent
Average Cost   2011   2010   Change
    (cents per net KWH)        
Fuel
    3.73       3.78       (1.3 )
Purchased power
    5.57       6.36       (12.4 )
 
In the first quarter 2011, fuel expense was $677 million compared to $758 million in the corresponding period in 2010. This decrease was due to an 11.1% decrease of KWHs generated as a result of lower KWH demand and a 1.3% decrease in the average cost of fuel per KWH generated.
Non-Affiliates
In the first quarter 2011, purchased power expense from non-affiliates was $74 million compared to $82 million in the corresponding period in 2010. This decrease was due to a 29.9% decrease in the volume of KWHs purchased due to lower demand as a result of the significantly colder weather in first quarter 2010, partially offset by a 29.6% increase in the average cost per KWH purchased.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Other Operations and Maintenance Expenses
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$33
  8.5
 
In the first quarter 2011, other operations and maintenance expenses were $422 million compared to $389 million in the corresponding period in 2010. This increase was primarily due to increases of $18 million in scheduled outages and maintenance at fossil generating plants, $7 million in transmission and distribution primarily due to maintenance of overhead lines, and $4 million in uncollectible account expense.
Depreciation and Amortization
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$59   51.8
 
In the first quarter 2011, depreciation and amortization was $173 million compared to $114 million in the corresponding period in 2010. This increase was primarily due to amortization of $10 million compared to $60 million in the first quarter 2011 and 2010, respectively, of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC and depreciation on additional plant in service related to transmission, distribution, and environmental projects. See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information on the other cost of removal regulatory liability.
Taxes Other Than Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$7   8.8
 
In the first quarter 2011, taxes other than income taxes were $87 million compared to $80 million in the corresponding period in 2010. This increase was primarily due to a $5 million increase in property tax in the first quarter 2011 compared to the corresponding period in 2010.
Allowance for Equity Funds Used During Construction
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(10)   (28.6)
 
In the first quarter 2011, AFUDC equity was $25 million compared to $35 million in the corresponding period in 2010. This decrease was due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC capitalized. See Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements herein under “State PSC Matters – Georgia Power – Nuclear Construction,” and FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for additional information.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$18   19.4
 
In the first quarter 2011, income taxes were $111 million compared to $93 million in the corresponding period in 2010. The increase in income taxes was primarily due to the recognition in the first quarter 2010 of certain state income tax credits that remain subject to litigation and a decrease in non-taxable AFUDC equity in the first quarter 2011, partially offset by lower pre-tax earnings. See 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 Notes (B) and (G) to the Condensed Financial Statements herein under “Income Tax Matters – Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, 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 timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Georgia Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.
In April 2010, the EPA proposed an Industrial Boiler MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. Georgia Power has delayed the decision to convert Plant Mitchell Unit 3 to biomass until there is greater clarity regarding these regulations. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Georgia Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Georgia Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia PSC Matters
Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information. As of March 31, 2011, Georgia Power had a total under recovered fuel cost balance of approximately $313 million compared to $398 million at December 31, 2010. 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 1, 2011, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 0.61%. The decrease would reduce Georgia Power’s annual billings by approximately $43 million. The decrease in fuel costs is driven primarily by lower natural gas prices than those included in current rates as a result of increases in natural gas supplies from the production of shale gas and lower industrial demand. If approved, the new rates will go into effect June 1, 2011. The ultimate outcome of this matter cannot be determined at this time.
Plant Branch Units 1 and 2 De-certification
See “Environmental Matters – Air Quality” and “– Water Quality” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality,” “– Water Quality,” and “– Coal Combustion Byproducts” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its coal-fired generating units in light of these regulations; and the 2010 ARP.
On March 22, 2011, the board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule. The proposed modifications would change the compliance dates for certain of Georgia Power’s coal-fired generating units as follows:
     
Scherer 3
  July 1, 2011
Branch 1
  December 31, 2013
Branch 2
  October 1, 2013
Branch 3
  October 1, 2015
Branch 4
  December 31, 2015
The Multi-Pollutant Rule is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. The Utility MACT rule will also regulate emissions of mercury, in addition to other air pollutants. All required controls, including SCR, scrubber, and baghouse, are expected to be operational at Plant Scherer Unit 3 by the required compliance date. As a result of these proposed rules, Georgia Power’s management expects to request that the Georgia PSC approve de-certification of its Plant Branch Units 1 and 2, totaling 569 MWs of capacity, as of the effective dates for controls under the Multi-Pollutant Rule as revised. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired units, including Plant Branch Units 3 and 4, in light of the proposed air quality rules, as well as additional potential federal regulations related to water quality and coal combustion byproducts. Georgia Power may determine that retiring and replacing certain of its existing units with new generating resources or purchased power is more economically efficient than installing the required controls.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated integrated resource plan will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Georgia Power currently expects to file an update to its integrated resource plan in late summer 2011, which would include the Plant Branch Units 1 and 2 de-certification request. In connection with this filing, Georgia Power expects to request the Georgia PSC to approve the deferral and related amortization of the retail portion of the related costs associated with the de-certification request. Georgia Power moved the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net of depreciation. Consistent with current ratemaking treatment, Georgia Power will continue to depreciate these units using the composite straight-line rates approved by the Georgia PSC, and upon actual retirement, expects to include the units’ remaining net carrying value in rate base. However, the recovery periods for these units may change in connection with Georgia Power’s updated integrated resource plan. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Georgia Power’s financial statements.
The ultimate outcome of these matters cannot be determined at this time.
Storm Damage Reserve
During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power maintains a reserve for property damage to cover the operating and maintenance cost of damages from major storms to its transmission and distribution lines as mandated by the Georgia PSC. As a result of this regulatory treatment, the storms are not expected to have a material impact on Georgia Power’s financial statements. See Note 1 to the financial statements of Georgia Power under “Storm Damage Reserve” in Item 8 of the Form 10-K for additional information.
Income Tax Matters
Bonus Depreciation
In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Georgia Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Georgia Power estimates the potential increased cash flow for 2011 to be between approximately $200 million and $275 million. The ultimate outcome of this matter cannot be determined at this time.
Construction
Nuclear
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 of the Form 10-K for information regarding the construction of Plant Vogtle Units 3 and 4.
In December 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the Construction and Operating License (COL) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. Georgia Power currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC’s February 16, 2011 release of its COL schedule framework.
On February 21, 2011, the Georgia PSC voted to approve Georgia Power’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the PSC

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related risk-sharing or incentive mechanism. A Georgia PSC hearing on this matter is scheduled on July 6, 2011 and a decision is expected on August 2, 2011. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.
In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs capitalized in 2009 and 2010 over the five-year period ending December 31, 2015 in addition to the ongoing financing costs. At March 31, 2011, approximately $87 million of these 2009 and 2010 costs are included in construction work in progress.
Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims, and anticipates that further issues are likely to arise in the future. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.
On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. According to published reports, the owner of these units is continuing work to stabilize these units following a loss of operation of the cooling systems for the units. While Georgia Power will continue to monitor this developing situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of its existing nuclear generating units.
The events in Japan have created uncertainties that may affect transportation, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. Similar additional challenges at the state and federal level are expected as construction proceeds.
The ultimate outcome of these matters cannot be determined at this time.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Construction
In May 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through June 30, 2010. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period.
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 U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the 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 GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Georgia Power’s financial condition remained stable at March 31, 2011. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $350 million for the first three months of 2011, compared to $327 million for the corresponding period in 2010. The $23 million increase is primarily due to higher recovery of fuel costs. Net cash used for investing activities totaled $428 million primarily due to gross property additions to utility plant in the first three months of 2011. Net cash provided from financing activities totaled $81 million for the first three months of 2011, compared to $268 million for the corresponding period in 2010. The $187 million decrease is primarily due to higher capital contributions from Southern Company in the first quarter 2010, partially offset by long-term debt issuances in the first quarter 2011.
Significant balance sheet changes for the first three months of 2011 include an increase of $361 million in total property, plant, and equipment, an increase of $238 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 $176 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, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $379 million will be required through March 31, 2012 to fund maturities and announced repurchases of long-term debt.
The construction program of Georgia Power is currently estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. In addition, Georgia Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million for 2011, $191 million to $651 million for 2012, and $476 million to $1.4 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Georgia Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Georgia Power in Item 7 of the Form 10-K for additional information.
In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by Georgia Power related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 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 COL for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. See FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for more information on Plant Vogtle Units 3 and 4.
Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at March 31, 2011 approximately $11 million of cash and cash equivalents and approximately $1.7 billion of unused committed credit arrangements with banks. As of March 31, 2011, of the unused credit arrangements, $595 million expire in 2011 and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2011 and 2012, $40 million contain provisions allowing for two-year term loans executable at expiration and $220 million contain provisions allowing for one-year term loans executable at expiration. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. At March 31, 2011, the credit arrangements were dedicated to providing liquidity support to Georgia Power’s commercial paper program and approximately $522 million of purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At March 31, 2011, Georgia Power had approximately $513 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, the maximum amount of commercial paper outstanding was $681 million and the average amount outstanding was $330 million. The weighted average annual interest rate on commercial paper in the first quarter 2011 was 0.3%. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.
Credit Rating Risk
Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. At March 31, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.4 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Market Price Risk
Georgia Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. 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 first quarter 2011 relative to fuel and electricity prices when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:
         
    First Quarter
    2011
    Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (100 )
Contracts realized or settled
    17  
Current period changes(a)
    (1 )
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (84 )
 
 
(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 ended March 31, 2011 was an increase of $16 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Georgia Power had a net hedge volume of 65.0 million mmBtu with a weighted average contract cost approximately $1.38 per mmBtu above market prices, compared to 58.7 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.74 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 months ended March 31, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

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GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:
                                 
    March 31, 2011
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
 
Level 1
  $     $     $     $  
Level 2
    (84 )     (70 )     (14 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (84 )   $ (70 )   $ (14 )   $  
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Georgia Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Georgia Power in Item 7 and Note 1 under “Financial Instruments” and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.
In January 2011, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.
In March 2011, Georgia Power’s $300 million variable rate bank term loan due on March 4, 2011 matured and was partially replaced by two one-year $125 million aggregate principal amount variable rate bank loans that bear interest based on one-month LIBOR.
Subsequent to March 31, 2011, Georgia Power issued $250 million aggregate principal amount of Series 2011B 3.0% Senior Notes due April 15, 2016. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.
Also subsequent to March 31, 2011, Georgia Power purchased and is holding $113.5 million of pollution control revenue bonds. The bonds are expected to be remarketed to investors at a future date.
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  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Revenues:
               
Retail revenues
  $ 274,826     $ 304,750  
Wholesale revenues, non-affiliates
    31,019       27,914  
Wholesale revenues, affiliates
    4,135       9,518  
Other revenues
    14,628       14,530  
 
           
Total operating revenues
    324,608       356,712  
 
           
Operating Expenses:
               
Fuel
    131,782       152,712  
Purchased power, non-affiliates
    7,003       7,435  
Purchased power, affiliates
    16,618       20,413  
Other operations and maintenance
    80,509       70,418  
Depreciation and amortization
    31,756       28,071  
Taxes other than income taxes
    24,896       25,233  
 
           
Total operating expenses
    292,564       304,282  
 
           
Operating Income
    32,044       52,430  
Other Income and (Expense):
               
Allowance for equity funds used during construction
    2,135       1,385  
Interest income
    14       17  
Interest expense, net of amounts capitalized
    (13,629 )     (11,385 )
Other income (expense), net
    (563 )     (533 )
 
           
Total other income and (expense)
    (12,043 )     (10,516 )
 
           
Earnings Before Income Taxes
    20,001       41,914  
Income taxes
    6,759       15,063  
 
           
Net Income
    13,242       26,851  
Dividends on Preference Stock
    1,551       1,551  
 
           
Net Income After Dividends on Preference Stock
  $ 11,691     $ 25,300  
 
           
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Net Income After Dividends on Preference Stock
  $ 11,691     $ 25,300  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Changes in fair value, net of tax of $- and $(953), respectively
          (1,518 )
Reclassification adjustment for amounts included in net income, net of tax of $90 and $105, respectively
    143       166  
 
           
Total other comprehensive income (loss)
    143       (1,352 )
 
           
Comprehensive Income
  $ 11,834     $ 23,948  
 
           
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 Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Activities:
               
Net income
  $ 13,242     $ 26,851  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    33,294       29,659  
Deferred income taxes
    6,249       2,917  
Allowance for equity funds used during construction
    (2,135 )     (1,385 )
Pension, postretirement, and other employee benefits
    (1,256 )     550  
Stock based compensation expense
    518       623  
Other, net
    (3,793 )     (520 )
Changes in certain current assets and liabilities —
               
-Receivables
    35,336       6,150  
-Prepayments
    1,156       983  
-Fossil fuel stock
    (14,941 )     17,419  
-Materials and supplies
    (726 )     (1,170 )
-Prepaid income taxes
    28,889       4,530  
-Property damage cost recovery
          11  
-Other current assets
    7       12  
-Accounts payable
    (8,863 )     (4,443 )
-Accrued taxes
    4,053       15,539  
-Accrued compensation
    (10,000 )     (3,462 )
-Other current liabilities
    6,127       6,304  
 
           
Net cash provided from operating activities
    87,157       100,568  
 
           
Investing Activities:
               
Property additions
    (94,239 )     (81,225 )
Distribution of restricted cash from pollution control revenue bonds
          2,340  
Cost of removal, net of salvage
    (5,314 )     (5,759 )
Change in construction payables
    3,171       (11,846 )
Payments pursuant to long-term service agreements
    (2,198 )     (699 )
Other investing activities
    68       (190 )
 
           
Net cash used for investing activities
    (98,512 )     (97,379 )
 
           
Financing Activities:
               
Decrease in notes payable, net
    (6,620 )     (6,599 )
Proceeds —
               
Common stock issued to parent
    50,000       50,000  
Capital contributions from parent company
    809       1,128  
Redemptions —
               
Senior notes
    (125 )     (85 )
Payment of preference stock dividends
    (1,551 )     (1,551 )
Payment of common stock dividends
    (27,500 )     (26,075 )
Other financing activities
    110       605  
 
           
Net cash provided from financing activities
    15,123       17,423  
 
           
Net Change in Cash and Cash Equivalents
    3,768       20,612  
Cash and Cash Equivalents at Beginning of Period
    16,434       8,677  
 
           
Cash and Cash Equivalents at End of Period
  $ 20,202     $ 29,289  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $851 and $552 capitalized for 2011 and 2010, respectively)
  $ 8,284     $ 9,461  
Income taxes (net of refunds)
    (29,557 )     (4,383 )
Noncash transactions — accrued property additions at end of period
    17,882       32,308  
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 March 31,     At December 31,  
Assets   2011     2010  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 20,202     $ 16,434  
Receivables —
               
Customer accounts receivable
    58,954       74,377  
Unbilled revenues
    44,970       64,697  
Under recovered regulatory clause revenues
    22,077       19,690  
Other accounts and notes receivable
    10,253       9,867  
Affiliated companies
    4,923       7,859  
Accumulated provision for uncollectible accounts
    (1,518 )     (2,014 )
Fossil fuel stock, at average cost
    182,096       167,155  
Materials and supplies, at average cost
    45,455       44,729  
Other regulatory assets, current
    16,849       20,278  
Prepaid expenses
    25,937       58,412  
Other current assets
    3,259       3,585  
 
           
Total current assets
    433,457       485,069  
 
           
Property, Plant, and Equipment:
               
In service
    3,738,908       3,634,255  
Less accumulated provision for depreciation
    1,087,442       1,069,006  
 
           
Plant in service, net of depreciation
    2,651,466       2,565,249  
Construction work in progress
    200,079       209,808  
 
           
Total property, plant, and equipment
    2,851,545       2,775,057  
 
           
Other Property and Investments
    16,284       16,352  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    49,920       46,357  
Prepaid pension costs
    7,998       7,291  
Other regulatory assets, deferred
    237,448       219,877  
Other deferred charges and assets
    29,288       34,936  
 
           
Total deferred charges and other assets
    324,654       308,461  
 
           
Total Assets
  $ 3,625,940     $ 3,584,939  
 
           
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Liabilities and Stockholder's Equity   2011     2010  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 110,000     $ 110,000  
Notes payable
    86,563       93,183  
Accounts payable —
               
Affiliated
    39,567       46,342  
Other
    67,856       68,840  
Customer deposits
    35,914       35,600  
Accrued taxes —
               
Accrued income taxes
    4,613       3,835  
Other accrued taxes
    11,754       7,944  
Accrued interest
    18,530       13,393  
Accrued compensation
    6,234       14,459  
Other regulatory liabilities, current
    22,860       27,060  
Liabilities from risk management activities
    7,167       9,415  
Other current liabilities
    18,863       19,766  
 
           
Total current liabilities
    429,921       449,837  
 
           
Long-term Debt
    1,114,406       1,114,398  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    396,377       382,876  
Accumulated deferred investment tax credits
    7,771       8,109  
Employee benefit obligations
    75,472       76,654  
Other cost of removal obligations
    205,373       204,408  
Other regulatory liabilities, deferred
    42,378       42,915  
Other deferred credits and liabilities
    145,382       132,708  
 
           
Total deferred credits and other liabilities
    872,753       847,670  
 
           
Total Liabilities
    2,417,080       2,411,905  
 
           
Preference Stock
    97,998       97,998  
 
           
Common Stockholder’s Equity:
               
Common stock, without par value—
               
Authorized - 20,000,000 shares
               
Outstanding - March 31, 2011: 4,142,717 shares
               
- December 31, 2010: 3,642,717 shares
    353,060       303,060  
Paid-in capital
    539,867       538,375  
Retained earnings
    220,519       236,328  
Accumulated other comprehensive loss
    (2,584 )     (2,727 )
 
           
Total common stockholder’s equity
    1,110,862       1,075,036  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,625,940     $ 3,584,939  
 
           
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Gulf Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(13.6)
  (53.8)
 
Gulf Power’s net income after dividends on preference stock for the first quarter 2011 was $11.7 million compared to $25.3 million for the corresponding period in 2010. The decrease was primarily due to increases in other operations and maintenance expenses in the first quarter 2011 and significantly colder weather in the first quarter 2010.
Retail Revenues
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(29.9)   (9.8)
 
In the first quarter 2011, retail revenues were $274.8 million compared to $304.7 million for the corresponding period in 2010.

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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:
                 
    First Quarter
    2011
    (in millions)   (% change)
Retail — prior year
  $ 304.7          
Estimated change in —
               
Rates and pricing
    (2.0 )     (0.7 )
Sales growth (decline)
    1.2       0.4  
Weather
    (9.5 )     (3.1 )
Fuel and other cost recovery.
    (19.6 )     (6.4 )
 
Retail — current year
  $ 274.8       (9.8 )%
 
Revenues associated with changes in rates and pricing decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower KWH energy sales.
Annually, Gulf Power petitions the Florida PSC for recovery of projected environmental compliance costs including any true-up amount from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the first quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential and commercial customers increased 2.0% and 2.2%, respectively, due to higher use per customer. KWH energy sales to industrial customers increased 7.9% primarily due to the addition of a new large customer and several customers buying more energy during maintenance outages of the customers’ onsite generation facilities.
Revenues attributable to changes in weather decreased in the first quarter 2011 when compared to the corresponding period for 2010 due to significantly colder weather in the first quarter 2010.
Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period for 2010 primarily due to lower fuel cost for generation and lower purchased power energy cost required to meet a lower level of KWH energy sales. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

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GULF POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$3.1
  11.1
 
Wholesale revenues from non-affiliates will vary depending on fuel prices, 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 first quarter 2011, wholesale revenues from non-affiliates were $31.0 million compared to $27.9 million for the corresponding period in 2010. The increase was primarily due to increased capacity revenues as a result of contracts effective in the second quarter 2010.
Wholesale Revenues – Affiliates
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(5.4)   (56.6)
   
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the first quarter 2011, wholesale revenues from affiliates were $4.1 million compared to $9.5 million for the corresponding period in 2010. The decrease was primarily due to a 43.7% decrease in price related to lower energy rates in the first quarter 2011 and decreased energy revenues related to a 22.9% decrease in KWH energy sales due to decreases in customer demand.
Fuel and Purchased Power Expenses
                 
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel*
  $ (21.0 )     (13.7 )
Purchased power — non-affiliates
    (0.4 )     (5.8 )
Purchased power — affiliates
    (3.8 )     (18.6 )
         
Total fuel and purchased power expenses
  $ (25.2 )        
         
*   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 first quarter 2011, total fuel and purchased power expenses were $155.4 million compared to $180.6 million for the corresponding period in 2010. The decrease in fuel and purchased power expenses was due to a $12.7 million decrease in the average cost of fuel and purchased power and a $12.5 million decrease related to total KWHs generated and purchased.

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Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Fuel Cost Recovery” herein for additional information.
Details of Gulf Power’s cost of generation and purchased power are as follows:
                         
    First Quarter   First Quarter   Percent
Average Cost   2011   2010   Change
    (cents per net KWH)        
Fuel
    4.69       5.11       (8.22 )
Purchased power
    5.37       5.56       (3.42 )
 
In the first quarter 2011, fuel expense was $131.8 million compared to $152.7 million for the corresponding period in 2010. The decrease was primarily due to a 45.3% decrease in the average cost of natural gas and a 1.7% decrease in KWHs generated as a result of decreased demand, partially offset by a 2.4% increase in the average cost of coal.
Non-Affiliates
In the first quarter 2011, purchased power expense from non-affiliates was $7.0 million compared to $7.4 million for the corresponding period in 2010. The decrease was primarily due to a 56.3% decrease in the volume of KWHs purchased, partially offset by an 18.3% increase in 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 first quarter 2011, purchased power expense from affiliates was $16.6 million compared to $20.4 million for the corresponding period in 2010. The decrease was primarily due to a 3.4% decrease in average cost per KWH purchased and a 16.5% decrease in the volume of KWHs purchased related to decreases in customer demand.
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
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$10.1
  14.3
 
In the first quarter 2011, other operations and maintenance expenses were $80.5 million compared to $70.4 million for the corresponding period in 2010. The increase was primarily due to planned outage maintenance expenses at Plant Crist.

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Depreciation and Amortization
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$3.7   13.1
 
In the first quarter 2011, depreciation and amortization was $31.8 million compared to $28.1 million for the corresponding period in 2010. The increase was primarily due to the addition of environmental control projects and other net additions to transmission and distribution facilities.
Allowance for Equity Funds Used During Construction
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$0.7   54.2
 
In the first quarter 2011, AFUDC equity was $2.1 million compared to $1.4 million for the corresponding period in 2010. The increase was primarily due to construction of environmental control projects.
Interest Expense, Net of Amounts Capitalized
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$2.2   19.7
 
In the first quarter 2011, interest expense, net of amounts capitalized was $13.6 million compared to $11.4 million for the corresponding period in 2010. The increase was primarily due to an increase in long-term debt resulting from the issuance of additional senior notes.
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(8.3)   (55.1)
 
In the first quarter 2011, income taxes were $6.8 million compared to $15.1 million for the corresponding period in 2010. The decrease was primarily due to lower pre-tax earnings.

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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 Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Changes in economic conditions impact sales for Gulf Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters — Carbon Dioxide Litigation – Kivalina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters — Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Gulf Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters — Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Gulf Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Gulf Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.
Florida PSC Matters
Fuel Cost Recovery
Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In previous years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. 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 March 31, 2011 totaled $19.8 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on Gulf Power’s revenues or net income, but would 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Cost Recovery
In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011, but a final order has not yet been issued. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in November 2011. The ultimate outcome of this matter cannot be determined at this time. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Cost Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.
Energy Conservation Cost Recovery
Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.
The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.
See BUSINESS under “Rate Matters – Integrated Resource Planning – Gulf Power” in Item 1 of the Form 10-K for a discussion of Gulf Power’s 10-year site plan filed on an annual basis with the Florida PSC.
Income Tax Matters
Bonus Depreciation
In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Gulf Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Gulf Power estimates the potential increased cash flow for 2011 to be between approximately $30 million and $40 million. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Gulf Power’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Gulf Power’s financial condition remained stable at March 31, 2011. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $87.2 million for the first three months of 2011 compared to $100.6 million for the corresponding period in 2010. The $13.4 million decrease was primarily due to a $32.4 million use of cash related to fuel inventory increases in 2011 compared to reductions in 2010, a $13.6 million decrease in net income, and an $8.4 million decrease due to payments to non-affiliates, partially offset by a $27.9 million increase related to the declining balance of customer receivables in 2011 compared to its increasing balance in 2010, which was driven by weather-related demands, and a $13.7 million increase from taxes primarily related to refunds received. Net cash used for investing activities totaled $98.5 million in the first three months of 2011 compared to $97.4 million for the corresponding period in 2010. The $1.1 million increase in cash used was primarily due to gross property additions. Net cash provided from financing activities totaled $15.1 million for the first three months of 2011, compared to $17.4 million for the corresponding period in 2010. The $2.3 million decrease was primarily due to higher common stock dividends in 2011.
Significant balance sheet changes for the first quarter 2011 include a net increase of $76.5 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 $32.5 million in prepaid expenses, primarily related to prepaid income taxes; and a $14.9 million increase in fossil fuel stock.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $110 million will be required through March 31, 2012 for maturities of long-term debt.
The construction program of Gulf Power is currently estimated to include a base level investment of $381.5 million, $395.5 million, and $384.1 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. In addition, Gulf Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations are up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as

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proposed, Gulf Power estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, a long-term bank note, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at March 31, 2011 approximately $20.2 million of cash and cash equivalents and $240 million of unused committed credit arrangements with banks that will expire in 2011. During the first quarter of 2011, one line of credit for $30 million was extended until July 2011. Subsequent to March 31, 2011, Gulf Power extended the maturity on two other lines of credit totaling $75 million until July 2011. Gulf Power expects to renew these lines of credit in July for at least a 364-day period. Of the credit arrangements, $210 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At March 31, 2011, Gulf Power had $83.0 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, Gulf Power had an average of $55 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $103 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.
Credit Rating Risk
Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $530 million. Included in these amounts are certain agreements

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Gulf Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. 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 and, to a lesser extent, into financial hedge contracts for natural gas purchases. Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.
The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:
         
    First Quarter
    2011
    Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (11 )
Contracts realized or settled
    2  
Current period changes(a)
    1  
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (8 )
 
(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 ended March 31, 2011 was an increase of $3 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Gulf Power had a net hedge volume of 20.3 million mmBtu with a weighted average contract cost approximately $0.46 per mmBtu above market prices, compared to 19.6 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $0.67 per mmBtu above market prices. Natural gas settlements 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 months ended March 31, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

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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 market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:
                                 
    March 31, 2011
    Fair Value Measurements
    Total   Maturity
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)
Level 1
  $     $     $     $  
Level 2
    (8 )     (5 )     (3 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (8 )   $ (5 )   $ (3 )   $  
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and Note 1 under “Financial Instruments” and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
On January 20, 2011, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.
Subsequent to March 31, 2011, Gulf Power extended the maturity date of a $110 million variable rate bank note until June 30, 2011.
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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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Revenues:
               
Retail revenues
  $ 180,474     $ 186,587  
Wholesale revenues, non-affiliates
    69,851       78,889  
Wholesale revenues, affiliates
    9,300       14,675  
Other revenues
    3,651       3,487  
 
           
Total operating revenues
    263,276       283,638  
 
           
Operating Expenses:
               
Fuel
    121,054       130,797  
Purchased power, non-affiliates
    1,010       3,621  
Purchased power, affiliates
    8,350       14,721  
Other operations and maintenance
    70,367       67,338  
Depreciation and amortization
    19,863       18,675  
Taxes other than income taxes
    17,481       18,460  
 
           
Total operating expenses
    238,125       253,612  
 
           
Operating Income
    25,151       30,026  
Other Income and (Expense):
               
Allowance for equity funds used during construction
    3,131       18  
Interest income
    342       33  
Interest expense, net of amounts capitalized
    (6,013 )     (6,179 )
Other income (expense), net
    (403 )     1,531  
 
           
Total other income and (expense)
    (2,943 )     (4,597 )
 
           
Earnings Before Income Taxes
    22,208       25,429  
Income taxes
    7,158       9,743  
 
           
Net Income
    15,050       15,686  
Dividends on Preferred Stock
    433       433  
 
           
Net Income After Dividends on Preferred Stock
  $ 14,617     $ 15,253  
 
           
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Net Income After Dividends on Preferred Stock
  $ 14,617     $ 15,253  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Changes in fair value, net of tax of $(1) and $12, respectively
    (2 )     20  
 
           
Comprehensive Income
  $ 14,615     $ 15,273  
 
           
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Activities:
               
Net income
  $ 15,050     $ 15,686  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    21,442       20,118  
Deferred income taxes
    10,015       (8,080 )
Investment tax credits received
    9,750        
Allowance for equity funds used during construction
    (3,131 )     (18 )
Pension, postretirement, and other employee benefits
    1,037       1,822  
Stock based compensation expense
    813       757  
Tax benefit of stock options
    73       24  
Generation construction screening costs
          (18,832 )
Other, net
    (1,436 )     1,138  
Changes in certain current assets and liabilities —
               
-Receivables
    11,592       7,715  
-Fossil fuel stock
    (538 )     17,761  
-Materials and supplies
    (317 )     (885 )
-Prepaid income taxes
    15,976        
-Other current assets
    1,649       (8,262 )
-Accounts payable
    17,538       970  
-Accrued taxes
    (31,213 )     (12,109 )
-Accrued compensation
    (9,556 )     (7,719 )
-Over recovered regulatory clause revenues
    7,756       7,596  
-Other current liabilities
    (149 )     (708 )
 
           
Net cash provided from operating activities
    66,351       16,974  
 
           
Investing Activities:
               
Property additions
    (148,917 )     (19,054 )
Cost of removal, net of salvage
    (2,830 )     (3,375 )
Construction payables
    33,291       2,812  
Capital grant proceeds
    16,912        
Distribution of restricted cash
    50,000        
Other investing activities
    (834 )     (5,316 )
 
           
Net cash used for investing activities
    (52,378 )     (24,933 )
 
           
Financing Activities:
               
Proceeds —
               
Capital contributions from parent company
    50,610       752  
Gross excess tax benefit of stock options
    106       75  
Redemptions —
               
Capital leases
    (349 )     (323 )
Other long-term debt
    (130,000 )      
Payment of preferred stock dividends
    (433 )     (433 )
Payment of common stock dividends
    (18,875 )     (17,150 )
Other financing activities
    (418 )     (1 )
 
           
Net cash used for financing activities
    (99,359 )     (17,080 )
 
           
Net Change in Cash and Cash Equivalents
    (85,386 )     (25,039 )
Cash and Cash Equivalents at Beginning of Period
    160,779       65,025  
 
           
Cash and Cash Equivalents at End of Period
  $ 75,393     $ 39,986  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $994 and $9 capitalized for 2011 and 2010, respectively)
  $ 6,135     $ 7,028  
Income taxes (net of refunds)
    (32,294 )     (3,821 )
Noncash transactions – accrued property additions at end of period
    72,114       6,501  
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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CONDENSED BALANCE SHEETS (UNAUDITED)
                         
    At March 31,     At December 31,  
Assets   2011     2010  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 75,393     $ 160,779  
Restricted cash and cash equivalents
          50,000  
Receivables —
               
Customer accounts receivable
    31,355       37,532  
Unbilled revenues
    25,992       31,010  
Other accounts and notes receivable
    9,345       11,220  
Affiliated companies
    30,905       17,837  
Accumulated provision for uncollectible accounts
    (467 )     (638 )
Fossil fuel stock, at average cost
    112,777       112,240  
Materials and supplies, at average cost
    28,988       28,671  
Other regulatory assets, current
    60,440       63,896  
Prepaid income taxes
    46,458       59,596  
Other current assets
    21,482       19,057  
 
           
Total current assets
    442,668       591,200  
 
           
Property, Plant, and Equipment:
               
In service
    2,416,242       2,392,477  
Less accumulated provision for depreciation
    980,896       971,559  
 
           
Plant in service, net of depreciation
    1,435,346       1,420,918  
Construction work in progress
    383,619       274,585  
 
           
Total property, plant, and equipment
    1,818,965       1,695,503  
 
           
Other Property and Investments
    6,111       5,900  
 
           
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    21,521       18,065  
Other regulatory assets, deferred
    128,379       132,420  
Other deferred charges and assets
    20,357       33,233  
 
           
Total deferred charges and other assets
    170,257       183,718  
 
           
Total Assets
  $ 2,438,001     $ 2,476,321  
 
           
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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CONDENSED BALANCE SHEETS (UNAUDITED)
                           
    At March 31,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 126,465     $ 256,437  
Accounts payable —
               
Affiliated
    48,146       51,887  
Other
    116,911       59,295  
Customer deposits
    13,181       12,543  
Accrued taxes —
               
Accrued income taxes
    8,753       4,356  
Other accrued taxes
    16,147       51,709  
Accrued interest
    5,132       5,933  
Accrued compensation
    6,521       16,076  
Other regulatory liabilities, current
    5,730       6,177  
Over recovered regulatory clause liabilities
    84,802       77,046  
Liabilities from risk management activities
    24,825       27,525  
Other current liabilities
    20,454       20,115  
 
           
Total current liabilities
    477,067       589,099  
 
           
Long-term Debt
    461,696       462,032  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    298,724       281,967  
Deferred credits related to income taxes
    12,096       11,792  
Accumulated deferred investment tax credits
    43,098       33,678  
Employee benefit obligations
    114,369       113,964  
Other cost of removal obligations
    115,192       111,614  
Other regulatory liabilities, deferred
    60,452       58,814  
Other deferred credits and liabilities
    37,865       43,213  
 
           
Total deferred credits and other liabilities
    681,796       655,042  
 
           
Total Liabilities
    1,620,559       1,706,173  
 
           
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
    444,344       392,790  
Retained earnings
    302,627       306,885  
Accumulated other comprehensive income (loss)
          2  
 
           
Total common stockholder’s equity
    784,662       737,368  
 
           
Total Liabilities and Stockholder’s Equity
  $ 2,438,001     $ 2,476,321  
 
           
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
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
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 and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, 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.
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
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(0.7)   (4.2)
   
Mississippi Power’s net income after dividends on preferred stock for the first quarter 2011 was $14.6 million compared to $15.3 million for the corresponding period in 2010. The decrease in net income after dividends on preferred stock for the first quarter 2011 was primarily due to an increase in other operations and maintenance expenses, a decrease in other income (expense), net primarily resulting from a decrease in amounts collected from customers for contributions in aid of construction, a decrease in capacity revenues from customers served outside Mississippi Power’s service territory, and a decrease in territorial base revenues due to significantly colder weather in the first quarter 2010. The decrease in net income after dividends on preferred stock for the first quarter 2011 was partially offset by an increase in AFUDC equity resulting from construction of the Kemper IGCC.
Retail Revenues
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(6.1)   (3.3)
   
In the first quarter 2011, retail revenues were $180.5 million compared to $186.6 million for the corresponding period in 2010.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the change to retail revenues are as follows:
                 
    First Quarter
    2011
    (in millions)   (% change)
Retail – prior year
  $ 186.6          
Estimated change in —
               
Rates and pricing
    1.0       0.5  
Sales growth (decline)
    3.5       1.9  
Weather
    (4.0 )     (2.2 )
Fuel and other cost recovery
    (6.6 )     (3.5 )
 
Retail – current year
  $ 180.5       (3.3 )%
 
Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 due to an increase of $1.0 million related to the ECO Plan rate. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Compliance Overview Plan” of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Mississippi PSC Matters – Retail Regulatory Matters – Environmental Compliance Overview Plan” herein for additional information.
Revenues attributable to changes in sales increased in the first quarter 2011 when compared to the corresponding period in 2010, primarily resulting from the continued recovery of some larger industrial customers. KWH energy sales to industrial customers increased 6.5% due to increased production for several large industrial customers resulting from improving economic conditions. Weather-adjusted KWH energy sales to the residential and commercial customers remained relatively flat when compared to the corresponding period in 2010.
Revenues attributable to changes in weather decreased in the first quarter 2011 when compared to the corresponding period for 2010 primarily due to significantly colder weather in the first quarter 2010.
Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(9.0)   (11.5)
   
Wholesale revenues from non-affiliates will vary depending on fuel prices, the market cost of available energy compared to the cost of Mississippi Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and the availability of Southern Company system generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
In the first quarter 2011, wholesale revenues from non-affiliates were $69.9 million compared to $78.9 million for the corresponding period in 2010. The decrease was due to $6.6 million in decreased revenues from customers inside Mississippi Power’s service territory and $2.4 million in decreased revenues from customers outside Mississippi Power’s

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
service territory. The $6.6 million decrease in revenues from customers inside Mississippi Power’s service territory was primarily due to a $6.1 million decrease in fuel revenues and a $0.5 million decrease in wholesale base revenues due to significantly colder weather in the first quarter 2010, partially offset by a wholesale base rate increase effective January 2011. The $2.4 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $1.1 million decrease in sales, a $0.5 million decrease associated with lower prices resulting from lower marginal cost of fuel, and a $0.8 million decrease in capacity revenues.
Wholesale Revenues – Affiliates
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(5.4)   (36.6)
   
Wholesale revenues from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.
In the first quarter 2011, wholesale revenues from affiliates were $9.3 million compared to $14.7 million for the corresponding period in 2010. The decrease was primarily due to a $4.4 million decrease in energy revenues, of which $2.9 million was associated with decreased sales and $1.5 million was associated with lower prices. Capacity revenues decreased by $1.0 million.
Fuel and Purchased Power Expenses
                 
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel
  $ (9.7 )     (7.4 )
Purchased power – non-affiliates
    (2.6 )     (72.1 )
Purchased power – affiliates
    (6.4 )     (43.3 )
         
Total fuel and purchased power expenses
  $ (18.7 )        
         
In the first quarter 2011, total fuel and purchased power expenses were $130.4 million compared to $149.1 million for the corresponding period in 2010. The decrease was primarily due to an $11.7 million decrease in cost of fuel and purchased power and a $7.0 million decrease in total KWHs generated and purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Mississippi PSC Matters – Retail Regulatory Matters” herein for additional information.
Details of Mississippi Power’s cost of generation and purchased power are as follows:
                         
    First Quarter   First Quarter   Percent
Average Cost   2011   2010   Change
    (cents per net KWH)        
Fuel
    3.92       4.23       (7.3 )
Purchased power
    3.08       3.76       (18.1 )
 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the first quarter 2011, fuel expense was $121.1 million compared to $130.8 million for the corresponding period in 2010. The decrease was primarily due to a 7.3% decrease in the price of fuel primarily resulting from lower gas prices and a 0.1% decrease in generation from Mississippi Power facilities resulting from lower energy demand in the first quarter 2011 compared to the corresponding period in 2010.
Non-Affiliates
In the first quarter 2011, purchased power expense from non-affiliates was $1.0 million compared to $3.6 million for the corresponding period in 2010. The decrease was primarily the result of a 54.2% decrease in the average cost of purchased power per KWH and a 39.1% decrease in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the decrease in volume was a result of higher cost opportunity purchases.
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 first quarter 2011, purchased power expense from affiliates was $8.3 million compared to $14.7 million for the corresponding period in 2010. The decrease was primarily due to a 37.3% decrease in KWH volume purchased and a 9.5% decrease in the average cost of purchased power per KWH.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$3.1   4.5
   
In the first quarter 2011, other operations and maintenance expenses were $70.4 million compared to $67.3 million for the corresponding period in 2010. The increase was primarily due to a $2.9 million increase in generation maintenance expenses for several major scheduled outages and a $1.0 million increase in expense for a combined cycle long-term service agreement due to a 29% increase in operating hours as a result of lower gas prices. These expenses were partially offset by a $0.7 million decrease in administrative and general expenses primarily due to pension costs and other employee benefits.
Depreciation and Amortization
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$1.2   6.4
   
In the first quarter 2011, depreciation and amortization was $19.9 million compared to $18.7 million for the corresponding period in 2010. The increase was primarily due to a $1.0 million increase in depreciation resulting from an increase in plant in service.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(1.0)   (5.3)
   
In the first quarter 2011, taxes other than income taxes were $17.5 million compared to $18.5 million for the corresponding period in 2010. The decrease was primarily due to a $1.3 million decrease in ad valorem taxes and a $0.2 million decrease in franchise taxes, partially offset by a $0.4 million increase in corporate franchise taxes and a $0.1 million increase in payroll taxes.
The retail portion of ad valorem taxes is recoverable under Mississippi Power’s ad valorem tax cost recovery clause and, therefore, does not affect net income.
Allowance for Equity Funds Used During Construction
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$3.1   N/M
   
N/M – Not meaningful
In the first quarter 2011, AFUDC equity increased $3.1 million as compared to the corresponding period in 2010 primarily due to increases in construction of the Kemper IGCC which began in June 2010 with the approval of the certificate order by the Mississippi PSC. See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(0.2)   (2.7)
   
In the first quarter 2011, interest expense, net of amounts capitalized was $6.0 million compared to $6.2 million for the corresponding period in 2010. The decrease was primarily due to a $1.0 million increase in AFUDC debt expense primarily associated with the Kemper IGCC, partially offset by a $0.7 million increase in interest expense associated with the issuance of new long-term debt in September and December 2010.
Other Income (Expense), Net
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
($1.9)   N/M
   
N/M – Not meaningful
In the first quarter 2011, other income (expense), net was ($0.4) million compared to $1.5 million for the corresponding period in 2010. The decrease was primarily due to a $1.5 million decrease in amounts collected from customers for contributions in aid of construction and a $0.5 million decrease in customer projects.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
 
(change in millions)   (% change)
$(2.5)   (26.5)
   
In the first quarter 2011, income taxes were $7.2 million compared to $9.7 million for the corresponding period in 2010. The decrease was primarily due to a $1.3 million decrease resulting from the decrease in pre-tax earnings and a $1.2 million decrease due to an increase in AFUDC equity which is non-taxable.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power’s future earnings potential. The level of Mississippi Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include Mississippi Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power’s service area. Changes in economic conditions impact sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.
Air Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Mississippi Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.
In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. In a decision published on April 6, 2011, the EPA responded to an environmental group’s request for reconsideration by attempting to rescind its previous approval of the Alabama SIP revision. Mississippi Power’s jointly-owned facility with Alabama Power in Greene County, Alabama is impacted by this decision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. Absent a stay, the EPA’s decision will become effective May 6, 2011 and the rule under which Alabama Power has been operating since January 2009 may not be available unless Alabama Power’s appeal is resolved in its favor by the court. If the EPA’s decision is allowed to take effect, it will likely impact unit availability and result in increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.
Water Quality
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing

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facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Mississippi Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Mississippi Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.
Mississippi PSC Matters
Retail Regulatory Matters
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.
In November 2010, Mississippi Power filed its annual PEP filing for 2011, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff (MPUS) contested the filing. The ultimate outcome of this matter cannot be determined at this time.
On March 15, 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. On May 2, 2011, Mississippi Power received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. The ultimate outcome of this matter cannot be determined at this time.
System Restoration Rider
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K for additional information.
On January 31, 2011, Mississippi Power submitted its 2011 SRR rate filing with the Mississippi PSC, which proposed that Mississippi Power be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. On May 5, 2011, the filing was approved by the Mississippi PSC.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.
On February 14, 2011, Mississippi Power submitted its ECO Plan notice which proposed an immaterial decrease in annual revenues. In addition, Mississippi Power proposed to change the ECO Plan collection period to more appropriately match ECO revenues with ECO expenditures. On April 7, 2011, due to changes in ECO Plan cost projections, Mississippi Power submitted a revised 2011 ECO Plan which changed the requested annual revenues to a $0.9 million decrease. On May 5, 2011, hearings on the revised ECO Plan were held and the filing was approved by the Mississippi PSC with the new rates effective in May 2011.
In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million with Mississippi Power’s portion being $312.5 million. As of March 31, 2011, total project expenditures were $19.5 million with Mississippi Power’s portion being $9.7 million. The project is scheduled for completion in early 2015. Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO

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Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011, but a final order has not yet been issued. On May 5, 2011, in conjunction with the ECO Plan hearings, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in November 2011. The ultimate outcome of this matter cannot be determined at this time.
Certificated New Plant
On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings would be made with the first filing occurring in November 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. Certificated New Plant-B, which will be filed at a later date, would propose to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2010. The Mississippi PSC approved the retail fuel cost recovery factor in December 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At March 31, 2011, the amount of over recovered retail fuel costs included in the balance sheets was $57.7 million compared to $55.2 million at December 31, 2010. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At March 31, 2011, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $21.6 million and $5.2 million compared to $17.5 million and $4.4 million, respectively, at December 31, 2010. In addition, at March 31, 2011, the amount of over recovered MRA emissions allowance cost included in the balance sheet was $0.4 million. See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factors will have no significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.
In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the retail fuel adjustment clause and energy cost management clause (ECM) for 2010. The audit was completed in the first quarter 2011 with no audit findings.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” and “PSC Matters – Mississippi Baseload Construction Legislation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.
In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an

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appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.
In May 2009, Mississippi Power received notification from the IRS formally certifying the IRS allocated Internal Revenue Code Section 48A tax credits (Phase I) of $133 million to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO2) produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2011, Mississippi Power received and accrued tax benefits totaling $31.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.
In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the plant and $25 million during the initial operation of the plant. Through March 31, 2011, Mississippi Power has received $40 million and requested an additional $20.1 million associated with this grant.
On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a stay on the issuance of CCPI2 funds and a stay to any related construction activities. On May 5, 2011, Mississippi Power filed a motion to intervene in this lawsuit.
In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein the permit board unanimously affirmed the PSD air permit.
On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract in which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC.
On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing CNP-A, a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. See “Mississippi PSC Matters – Retail Regulatory Matters – Certificated New Plant” herein for additional information.
Events in Japan resulting from the earthquake and tsunami created uncertainties that may affect transportation and availability of equipment or supplies from Japanese manufacturers in connection with the construction of the Kemper IGCC.
As of March 31, 2011, Mississippi Power had spent a total of $352.8 million on the Kemper IGCC, including regulatory filing costs. Of this total, $277 million was included in CWIP (net of $60.1 million of CCPI2 grant funds), $13.2 million was recorded in other regulatory assets, $1.5 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.
The ultimate outcome of these matters cannot be determined at this time.

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Income Tax Matters
Bonus Depreciation
In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Mississippi Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Mississippi Power estimates the potential increased cash flow for 2011 to be between approximately $15 million and $20 million. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Mississippi Power’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, Plant Daniel Operating Lease, and Pension and Other Postretirement Benefits.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
Mississippi Power’s financial condition remained stable at March 31, 2011. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.
Net cash provided from operating activities totaled $66.4 million for the first three months of 2011 compared to $17.0 million for the corresponding period in 2010. The $49.4 million increase in cash provided from operating activities is primarily due to an $18.1 million increase in deferred income taxes primarily related to bonus depreciation, an increase in accounts payable of $16.6 million primarily due to timing of cash payments, an increase in investment tax credits of $9.7 million related to the Kemper IGCC, and an increase in cash of $18.8 million related to the Kemper IGCC generation construction screening costs incurred during the first quarter 2010. The Mississippi PSC issued an order in June 2010 approving the Kemper IGCC. These increases in cash are partially offset by a decrease of $18.3 million in fossil fuel stock resulting from an increase in Mississippi Power generation and a decrease in cash payments related to fuel inventory in the first quarter 2010.
Net cash used for investing activities totaled $52.4 million for the first three months of 2011 compared to $24.9 million for the corresponding period in 2010. The $27.4 million increase in net cash used for investing activities is primarily due to an increase in property additions of $129.9 million primarily related to the Kemper IGCC, partially offset by a $50.0 million decrease in restricted cash, a construction payables increase of $30.5 million, and the receipt of $16.9 million capital grant proceeds related to CCPI2.
Net cash used for financing activities totaled $99.4 million for the first three months of 2011, compared to net cash provided from financing activities of $17.1 million for the corresponding period in 2010. The $82.3 million increase in net cash used for financing activities was primarily due to the redemption of $50.0 million in revenue bonds and an $80.0 million maturity of long-term debt, partially offset by a $49.9 million increase in capital contributions from Southern Company.
Significant balance sheet changes for the first three months of 2011 include a decrease in cash and cash equivalents of $85.4 million primarily due to an $80.0 million long-term debt maturity and increased capital spending. Restricted cash and cash equivalents decreased $50.0 million due to the redemption of revenue bonds in February 2011. Total property, plant, and equipment increased $123.5 million primarily due to the increase in construction work in progress (CWIP) related to the Kemper IGCC. Other deferred charges and assets decreased $12.9 million primarily due to the reclassification of the Plant Daniel scrubber project and materials and supplies to CWIP. Securities due within one year decreased $130.0 million primarily due to a long-term bank loan of $80.0 million that matured in March 2011 and the redemption of revenue bonds of $50.0 million in February 2011. Other accounts payable increased $57.6 million primarily due to increases in construction projects. Other accrued taxes decreased $35.6 million primarily due to property tax payments of $44.1 million in the first quarter 2011. Paid-in capital increased $51.6 million primarily due to the $50.0 million capital contribution from Southern Company.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $126.5 million will be required through March 31, 2012 for maturities of long-term debt.

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The construction program of Mississippi Power is currently estimated to include a base level investment of $818 million, $1.0 billion, and $878 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $685 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively. Also included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $20 million, $93 million, and $127 million for 2011, 2012, and 2013, respectively. In addition, Mississippi Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations are $0 for 2011, up to $18 million for 2012, and up to $55 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Mississippi Power estimates that the potential incremental investments in 2012 and 2013 for new environmental regulations will be closer to the upper end of the estimates set forth above. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Except as described below with respect to potential DOE loan guarantees, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Mississippi Power has primarily utilized funds from operating cash flows, short-term borrowings, external security offerings, and capital contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. In March 2011, Mississippi Power received a $50 million capital contribution from Southern Company. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In addition, Mississippi Power has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used for the initial operation of the Kemper IGCC. As of March 31, 2011, Mississippi Power had received $40.0 million and requested an additional $20.1 million associated with this grant.
Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at March 31, 2011 approximately $75.4 million of cash and cash equivalents and $186 million of unused committed credit arrangements with banks. Of the unused credit arrangements, $161 million expire in 2011 and $25 million expire in 2012. Of these credit arrangements, $41 million contain provisions allowing for two-year term loans executable at expiration and $90 million contain provisions allowing for one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. During the three months ended March 31, 2011,

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Mississippi Power had no commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.
Off-Balance Sheet Financing Arrangements
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” of Mississippi Power in Item 7 and Note 7 to the financial statements of Mississippi Power under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power is required 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
Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $335 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.
Market Price Risk
Mississippi Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.
Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.

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The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:
         
    First Quarter
    2011
    Changes
    Fair Value
    (in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net
  $ (44 )
Contracts realized or settled
    7  
Current period changes(a)
     
 
Contracts outstanding at the end of the period, assets (liabilities), net
  $ (37 )
 
     
(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 ended March 31, 2011 was an increase of $7 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2011, Mississippi Power had a net hedge volume of 24.3 million mmBtu with a weighted average contract cost approximately $1.79 per mmBtu above market prices, compared to 24.0 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.92 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the ECM.
Regulatory hedges relate to Mississippi Power’s fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM.
Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.
Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:
                                 
    March 31, 2011  
    Fair Value Measurements  
    Total   Maturity  
    Fair Value   Year 1   Years 2&3   Years 4&5
    (in millions)  
Level 1
  $     $     $     $  
Level 2
    (37 )     (24 )     (13 )      
Level 3
                       
 
Fair value of contracts outstanding at end of period
  $ (37 )   $ (24 )   $ (13 )   $  
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Mississippi Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Mississippi Power in Item 7 and Note 1 under “Financial Instruments” and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.
Financing Activities
On February 8, 2011, Mississippi Power redeemed a $50 million series of revenue bonds issued in December 2010.
On March 4, 2011, an $80 million long term bank note with a variable interest rate based on one-month LIBOR matured.
In addition, subsequent to March 31, 2011, Mississippi Power entered into a one-year $75 million aggregate principal amount long-term floating rate bank loan with a variable interest rate based on one-month LIBOR. The proceeds of this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including Mississippi Power’s continuous construction program.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, Mississippi Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Revenues:
               
Wholesale revenues, non-affiliates
  $ 197,166     $ 153,337  
Wholesale revenues, affiliates
    83,274       101,757  
Other revenues
    1,347       1,394  
 
           
Total operating revenues
    281,787       256,488  
 
           
Operating Expenses:
               
Fuel
    102,715       97,514  
Purchased power, non-affiliates
    8,942       18,542  
Purchased power, affiliates
    15,099       23,411  
Other operations and maintenance
    42,754       39,010  
Depreciation and amortization
    30,167       29,109  
Taxes other than income taxes
    4,763       5,106  
 
           
Total operating expenses
    204,440       212,692  
 
           
Operating Income
    77,347       43,796  
Other Income and (Expense):
               
Interest expense, net of amounts capitalized
    (18,829 )     (20,054 )
Other income (expense), net
    59       418  
 
           
Total other income and (expense)
    (18,770 )     (19,636 )
 
           
Earnings Before Income Taxes
    58,577       24,160  
Income taxes
    20,834       9,436  
 
           
Net Income
  $ 37,743     $ 14,724  
 
           
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Net Income
  $ 37,743     $ 14,724  
Other comprehensive income (loss):
               
Qualifying hedges:
               
Changes in fair value, net of tax of $423 and $1,714, respectively
    643       2,677  
Reclassification adjustment for amounts included in net income, net of tax of $1,071 and $1,003, respectively
    1,630       1,567  
 
           
Total other comprehensive income (loss)
    2,273       4,244  
 
           
Comprehensive Income
  $ 40,016     $ 18,968  
 
           
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
                 
    For the Three Months  
    Ended March 31,  
    2011     2010  
    (in thousands)  
Operating Activities:
               
Net income
  $ 37,743     $ 14,724  
Adjustments to reconcile net income to net cash provided from operating activities —
               
Depreciation and amortization, total
    33,580       32,355  
Deferred income taxes
    8,601       13,388  
Convertible investment tax credits received
    38,068        
Deferred revenues
    (21,476 )     (20,993 )
Mark-to-market adjustments
    (63 )     762  
Other, net
    1,752       930  
Changes in certain current assets and liabilities —
               
-Receivables
    20,759       16,566  
-Fossil fuel stock
    625       3,815  
-Materials and supplies
    253       4,721  
-Prepaid income taxes
    15,744       (9,248 )
-Other current assets
    (137 )     1,020  
-Accounts payable
    (21,645 )     (15,111 )
-Accrued taxes
    4,888     3,433  
-Accrued interest
    (12,281 )     (12,028 )
-Other current liabilities
    (519 )     297  
 
           
Net cash provided from operating activities
    105,892       34,631  
 
           
Investing Activities:
               
Property additions
    (113,518 )     (68,179 )
Change in construction payables
    43,259       15,489  
Payments pursuant to long-term service agreements
    (11,320 )     (8,145 )
Other investing activities
    (3,165 )     (245 )
 
           
Net cash used for investing activities
    (84,744 )     (61,080 )
 
           
Financing Activities:
               
Increase (decrease) in notes payable, net
    (20,360 )     48,006  
Proceeds — Capital contributions
    17,179       1,632  
Repayments — Other long-term debt
    (3,066 )      
Payment of common stock dividends
    (22,800 )     (26,775 )
Other financing activities
    38       95  
 
           
Net cash provided from (used for) financing activities
    (29,009 )     22,958  
 
           
Net Change in Cash and Cash Equivalents
    (7,861 )     (3,491 )
Cash and Cash Equivalents at Beginning of Period
    14,204       7,152  
 
           
Cash and Cash Equivalents at End of Period
  $ 6,343     $ 3,661  
 
           
Supplemental Cash Flow Information:
               
Cash paid during the period for —
               
Interest (net of $4,240 and $1,926 capitalized for 2011 and 2010, respectively)
  $ 26,993     $ 28,900  
Income taxes (net of refunds)
    (44,721 )     1,532  
Noncash transactions — accrued property additions at end of period
    78,567       30,963  
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Assets   2011     2010  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 6,343     $ 14,204  
Receivables —
               
Customer accounts receivable
    65,359       77,033  
Other accounts receivable
    2,388       1,979  
Affiliated companies
    10,473       19,673  
Fossil fuel stock, at average cost
    13,209       13,663  
Materials and supplies, at average cost
    34,356       33,934  
Prepaid service agreements — current
    33,272       41,627  
Prepaid income taxes
    10,343       53,860  
Other prepaid expenses
    4,297       4,161  
Assets from risk management activities
    2,811       2,160  
Other current assets
          19  
 
           
Total current assets
    182,851       262,313  
 
           
Property, Plant, and Equipment:
               
In service
    3,149,499       3,143,919  
Less accumulated provision for depreciation
    562,973       536,107  
 
           
Plant in service, net of depreciation
    2,586,526       2,607,812  
Construction work in progress
    538,067       427,788  
 
           
Total property, plant, and equipment
    3,124,593       3,035,600  
 
           
Other Property and Investments:
               
Goodwill
    1,839       1,839  
Other intangible assets, net of amortization of $889 and $693 at March 31, 2011 and December 31, 2010, respectively
    48,231       48,426  
 
           
Total other property and investments
    50,070       50,265  
 
           
Deferred Charges and Other Assets:
               
Prepaid long-term service agreements
    80,134       69,740  
Other deferred charges and assets — affiliated
    3,213       3,275  
Other deferred charges and assets — non-affiliated
    20,214       16,541  
 
           
Total deferred charges and other assets
    103,561       89,556  
 
           
Total Assets
  $ 3,461,075     $ 3,437,734  
 
           
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
                 
    At March 31,     At December 31,  
Liabilities and Stockholder’s Equity   2011     2010  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 253     $  
Notes payable — affiliated
          65,883  
Notes payable — non-affiliated
    249,427       203,904  
Accounts payable —
               
Affiliated
    46,536       69,783  
Other
    89,075       45,985  
Accrued taxes —
               
Accrued income taxes
    2,390       812  
Other accrued taxes
    6,005       2,775  
Accrued interest
    17,696       29,977  
Liabilities from risk management activities
    5,553       5,773  
Other current liabilities
    3,512       3,923  
 
           
Total current liabilities
    420,447       428,815  
 
           
Long-term Debt
    1,299,364       1,302,619  
 
           
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    317,738       307,989  
Deferred convertible investment tax credits
    90,965       80,401  
Deferred capacity revenues — affiliated
    9,763       30,533  
Other deferred credits and liabilities — affiliated
    4,376       4,635  
Other deferred credits and liabilities — non-affiliated
    17,450       16,203  
 
           
Total deferred credits and other liabilities
    440,292       439,761  
 
           
Total Liabilities
    2,160,103       2,171,195  
 
           
Redeemable Noncontrolling Interest
    3,357       3,319  
 
           
Common Stockholder’s Equity:
               
Common stock, par value $.01 per share —
               
Authorized - 1,000,000 shares
               
Outstanding - 1,000 shares
           
Paid-in capital
    918,148       900,969  
Retained earnings
    391,213       376,270  
Accumulated other comprehensive loss
    (11,746 )     (14,019 )
 
           
Total common stockholder’s equity
    1,297,615       1,263,220  
 
           
Total Liabilities and Stockholder’s Equity
  $ 3,461,075     $ 3,437,734  
 
           
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2011 vs. FIRST QUARTER 2010
OVERVIEW
Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs with investor owned utilities, independent power producers, municipalities, and electric cooperatives.
Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE) to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.
To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR) and net income. EFOR defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). Net income is the primary measure of Southern Power’s financial performance. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$23.0
  156.3
 
Southern Power’s net income for the first quarter 2011 was $37.7 million compared to $14.7 million for the corresponding period in 2010. The increase was primarily due to higher energy and capacity revenues under new PPAs that began in June, July, and December 2010 and January 2011. The increase was partially offset by lower energy and capacity revenues under existing PPAs and the expiration of PPAs in May and December 2010, lower revenues from energy sales that were not covered by PPAs, higher other operations and maintenance expenses, and higher income taxes.
Wholesale Revenues Non-Affiliates
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$43.9   28.6
 
Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market cost of available energy compared to the cost of Southern Power’s energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale revenues from non-affiliates for the first quarter 2011 were $197.2 million compared to $153.3 million for the corresponding period in 2010. The increase was mainly due to $88.1 million of energy and capacity revenues under new non-affiliate PPAs that began in June, July, and December 2010 and January 2011. These increases were partially offset by $31.0 million of lower revenues from energy sales that were not covered by PPAs as a result of significantly more favorable weather in the first quarter 2010 compared to 2011, and $13.3 million of lower energy and capacity revenues under existing non-affiliate PPAs and the expiration of a non-affiliate PPA in December 2010.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.
Wholesale Revenues Affiliates
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(18.5)   (18.2)
 
Wholesale energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Wholesale revenues from affiliates for the first quarter 2011 were $83.3 million compared to $101.8 million for the corresponding period in 2010. The decrease was primarily the result of $27.4 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in May 2010 and $9.2 million related to lower revenues from power sales to affiliates under the IIC. These decreases were partially offset by $18.5 million of increased energy and capacity revenues associated with new affiliate PPAs that began in June 2010.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.
Fuel and Purchased Power Expenses
                     
First Quarter 2011 vs. First Quarter 2010
    (change in millions)   (% change)
Fuel
  $ 5.2       5.3  
Purchased power – non-affiliates
    (9.6 )     (51.8 )
Purchased power – affiliates
    (8.3 )     (35.5 )
         
Total fuel and purchased power expenses
  $ (12.7 )        
         
Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.
In the first quarter 2011, total fuel and purchased power expenses were $126.8 million compared to $139.5 million for the corresponding period in 2010. Fuel and purchased power expenses decreased $42.9 million due to a 19.3% decrease in the average cost of natural gas and a 43.3% decrease in the average cost of purchased power. This decrease was partially offset by a $30.2 million increase in volume of KWHs generated and purchased.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the first quarter 2011, fuel expense was $102.7 million compared to $97.5 million for the corresponding period in 2010. Fuel expense increased $29.7 million due to an increase in the volume of KWHs generated. This increase was partially offset by $24.5 million associated with a 19.3% decrease in the average cost of natural gas.
In the first quarter 2011, purchased power expense was $24.0 million compared to $41.9 million for the corresponding period in 2010. Purchased power expenses decreased $18.4 million due to a 43.3% decrease in the average cost of purchased power partially offset by $0.5 million associated with an increase in the volume of KWHs purchased.
Other Operations and Maintenance Expenses
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$3.7
  9.6
 
In the first quarter 2011, other operations and maintenance expenses were $42.7 million compared to $39.0 million for the corresponding period in 2010. This increase was primarily due to a $4.8 million increase related to more generating plant scheduled outages in the first quarter 2011 compared to the corresponding period in 2010 and an unplanned outage at a combined cycle generating plant. These increases were partially offset by a $1.1 million decrease in salaries and wages relating mainly to higher payroll taxes in the first quarter of 2010.
Interest Expense, Net of Amounts Capitalized
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$(1.2)   (6.1)
 
In the first quarter 2011, interest expense, net of amounts capitalized was $18.8 million compared to $20.0 million for the corresponding period in 2010. The decrease was primarily due to an increase in capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant. See FUTURE EARNINGS POTENTIAL – “Construction Projects” herein for additional information.
Income Taxes
     
First Quarter 2011 vs. First Quarter 2010
(change in millions)   (% change)
$11.4   120.8
 
In the first quarter 2011, income taxes were $20.8 million compared to $9.4 million for the corresponding period in 2010 primarily due to higher pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs, regulatory matters, creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
levels. The timing and extent of the economic recovery is uncertain and will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Environmental Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also affect earnings. While Southern Power’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.
Carbon Dioxide Litigation
Kivalina Case
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.
Water Quality
On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at some of Southern Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Southern Power’s facilities may be subject to varying degrees of additional capital expenditures and compliance costs. While Southern Power’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Construction Projects
Cleveland County Units 1-4
In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. Costs incurred through March 31, 2011 were $239.2 million. The total estimated construction cost is expected to be between $350 million and $400 million.
Nacogdoches Biomass Plant
In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through March 31, 2011 were $296.1 million. The total estimated cost of the project is expected to be between $475 million and $500 million.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Power’s financial statements.
See Note (B) to the Condensed Financial Statements herein for discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power’s critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Contingent Obligations, Depreciation, and Convertible Investment Tax Credits (ITCs).

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power’s financial condition remained stable at March 31, 2011. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See “Sources of Capital” herein for additional information on lines of credit.
Net cash provided from operating activities totaled $105.9 million for the first three months of 2011, compared to $34.6 million for the corresponding period in 2010. This increase was mainly due to an increase in cash received for convertible ITCs and bonus depreciation. Net cash used for investing activities totaled $84.7 million for the first three months of 2011, compared to $61.1 million for the corresponding period in 2010. This increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $29.0 million for the first three months of 2011, compared to $23.0 million cash provided from financing activities for the corresponding period in 2010 primarily due to repayment of an affiliate loan related to SRE.
Significant asset changes in the balance sheet for the first quarter 2011 include an increase in construction work in progress due to Cleveland County and Nacogdoches construction activities and a decrease in prepaid income taxes mainly due to the receipt of an income tax refund from the IRS related to convertible ITCs and bonus depreciation.
Significant liability and stockholder’s equity changes in the balance sheet for the first quarter 2011 include an increase in accounts payable – other primarily related to Cleveland County and Nacogdoches construction activities, a decrease in accounts payable – affiliated primarily due to the expiration of affiliate PPAs in May 2010, a decrease in notes payable primarily due to repayment of an affiliate loan related to SRE, and a decrease in deferred capacity revenues – affiliated primarily due to seasonality.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.
Sources of Capital
Southern Power may use operating cash flows, external funds, equity capital, or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Power in Item 7 of the Form 10-K for additional information.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at March 31, 2011 cash and cash equivalents of approximately $6 million and committed credit arrangements with banks of $400 million, all of which expire in 2012. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Southern Power’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At March 31, 2011, Southern Power had $249 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the first quarter 2011, Southern Power had an average of $231 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $272 million. Management believes that the need for working capital can be adequately met by utilizi